Session 2010-12
Publications on the internet










Evidence heard in Public

Questions 224 - 286



This is a corrected transcript of evidence taken in public and reported to the House. The transcript has been placed on the internet on the authority of the Committee, and copies have been made available by the Vote Office for the use of Members and others.


The transcript is an approved formal record of these proceedings. It will be printed in due course.

Oral Evidence

Taken before the Energy and Climate Change Committee

on Tuesday 15 February 2011

Members present:

Mr Tim Yeo (Chair)

Ian Lavery

Albert Owen

Laura Sandys

Dr Alan Whitehead

Examination of Witnesses

Witnesses: Robert Cross, Head of Government and Regulatory Affairs, Natural Gas, Statoil, Adrian Haworth, Director of Market Development, Europe, GE Energy, Joan MacNaughton, Senior Vice President, Power and Environmental Policies, Alstom Power, and Christina Grumstrup Sorensen, Senior Vice President of Renewables, DONG Energy, gave evidence.

Q224 Chair: Good morning. Thank you very much for coming in. You know that we’ve been looking at electricity market reform during our last few sittings. Obviously, it’s a highly topical but wide-ranging subject. We have about an hour with you. Please feel free to participate in any discussion that you want to, but don’t feel obliged to answer every single question if you don’t feel you have anything particular to add to what has already been said.

I start with a general question about whether you think that the proposals in the consultation document are likely to promote investment in low-carbon power. Will the proposals reduce some of the risks that are already inherent in such investment?

Joan MacNaughton: Alstom begins with A, so perhaps I should go first.

We strongly support the objectives of the reform, and we strongly support the goal of decarbonisation. Because we think that all of the technologies will be required-we actually have an offer for all of the technologies-you will need a varied portfolio, which is essential to maintaining security of supply and minimising the cost to the consumer. As well as those technologies, you need to drive up efficiency of power generation, and you need to drive carbon capture and storage.

Will the current proposals succeed? It is very difficult to tell on the information currently available. There are big design issues with the contract for difference, which are acknowledged in the consultation document itself. There is no certainty about the proposed rate of decarbonisation. We are not absolutely clear about the trajectory on either price or carbon intensity.

There are a whole lot of questions that need to be answered. There are a lot of questions on the interaction between the different proposals, which need to be pulled through and made more visible. Until we have visibility on that, it is quite difficult to be confident that this is going to drive the real uplift in investment that is absolutely crucial.

Christina Grumstrup Sorensen: My name is Christina Sorensen from DONG Energy. We generally welcome the energy market reform, and we believe that it is a reform of this nature, and with this ambition and will, that is needed to ensure that we achieve the challenges in front of us.

We both talk about the aggressive capacity build-up plans that are needed; we also need to attract new investors to achieve the emission targets. We also talk about working towards security of supply and about the role of the different technologies in the electricity system. We also talk about the need for affordability, which means supporting the low-carbon and renewable technologies that are at hand right now.

We are concerned that one of the main risks is that market liquidity is not targeted directly in this energy market reform; we believe that market liquidity is a prerequisite for many of the initiatives to be successful. We also believe that auctions as a means of delivering the feed-in tariffs will be disruptive to the build-up plans, because planning is needed. We need to bring down costs, to build a supply chain and to attract new investors, so we really need a stable investment environment.

Lastly, we believe that the timing of the energy market reform is a challenge. It is a challenge to balance getting certainty on these big initiatives and, at the same time, working them to the right detail level to ensure that the incentives are correctly aligned to achieve the objectives.

Adrian Haworth: I speak on behalf of GE. We are looking right now at substantial investment, certainly in the offshore wind sector, and the timing is crucial. We believe the UK has a unique circumstance where it can lead the world in offshore wind; it can develop that technology and export it in future. But right now, we need to ensure that the momentum is not lost-that investment in the offshore sector is kept in the UK and does not move to other countries that are also competing to be the supplier to this newly developing technology. We see it as being like the oil and gas sector 30 years ago. We have recently made several acquisitions in the oil and gas sector, in which we would never have been in the UK had we not moved 30 or 40 years ago. We think now is the time to move into the offshore market and make the UK a leader, because it is unique in the world to be able to do that.

Robert Cross: Statoil would support the reform, but I think that generates a great deal of uncertainty for investors. From an offshore wind perspective, we are quite happy with the renewables obligation. We have almost completed our investment in the Scira wind project. More generally speaking, we have some concerns about the impact that these changes will have on the structure of the electricity market, and the consequences that that will have on other markets that relate to the electricity market, such as the gas market. Some of the measures may be necessary, but perhaps not all of them all at the same time, because that creates a great deal of instability.

Q225 Chair: Given the scale of the investment needed, a variety of investors will have to participate in this, who may have slightly different objectives, looking for a return over different time periods. Is it possible to produce one set of policies that maximises the attraction to investors with different objectives?

Christina Grumstrup Sorensen: I think the initiatives that are set out in the EMR and that are multiple, will work well hand-in-hand. So I don’t see that we should need less compromise and only have one initiative for one. For the feed-in tariffs as well as the RO banding, there has been this banding that has given different support to different technologies. We see that as an example of how a mechanism can work well with different technologies.

Adrian Haworth: Offshore wind has many risks associated with it, and they are not all financial. There is a lot of technology risk, which needs to be understood. We believe that eventually there will be economies of scale, but right now we need to get experience offshore. We need to understand that technology better; then we can develop further. Getting offshore established and started is going to be an issue. I don’t think there will be one mechanism that suits a developing technology and a mature technology. That is the problem for offshore wind.

Joan MacNaughton: I think the particular risks of the new technologies and of the large-scale technologies mean that the investors need predictability over a time scale. That doesn’t mean that you need a single instrument that can fit all, but you do need confidence in the direction and pace of travel. There is quite a focus on 2020; there is a target at 2030 that we know about, although the Climate Change Committee has made a recommendation to toughen that target. But we don’t have clear visibility of what the trajectory is, yet for a lot of these investments the payback period really will have go over that 20-year period at a minimum.

I do think we need more granularity around what is said in the document about how some of these decisions are going to be taken. If you take the contract for difference, which has a lot to commend it as a proposal, we don’t yet know how it is going to apply across the different technologies, and how the strike price is going to be set. Until investors have some confidence in those issues-not just the formal statement, but how that regulatory regime is going to work in practice-there will be a high value to wait-and-see. And that is actually what we don’t want; we don’t want the hiatus in investment.

Q226 Chair: Given the absolutely overriding need for predictability, we heard evidence last week from someone who suggested that the potential cost to consumers of achieving quite challenging targets for renewable energy, and climate change more generally, was such that investors might be nervous that a future Government might lose their nerve in terms of what is going to happen to people’s household bills and so on. If people thought that the consequences for consumers might become too much for the Government to stick to their commitments, might they be deterred from making long-term investments?

Adrian Haworth: Yes. I don’t think it’s just the UK. In Europe generally, a lot of people think that once the cost of leading the world in carbon abatement is realised, they’ll back off. But I think there is the political will throughout Europe, and especially here in the UK, from all parties and walks of life. People are willing to pay the little extra for a renewable future. Perhaps that needs to be better stated to people outside the UK who are the potential investors and who may not have the confidence that the people in the UK seem to have in the Government’s binding contract for the future. Certainly there are sceptics outside the UK.

Robert Cross: There does need to be a great deal more transparency about what the impact on consumers’ bills will be and the effects that these policies will have on the prices that they pay. The other issue is the availability of capital to make all these investments all at the same time, which may, in itself, drive up some of those costs. I think that there are options available to policy makers that will allow other pathways to be achieved in conjunction with the investments that are being made, such as relying on natural gas generation to some extent to soften the impact of that trajectory.

Joan MacNaughton: I understand the point about the pace. The pace could accelerate or it could slow down a bit if people did begin to lose their nerve-to use your phrase, Chair. What we’ve been seeing over the last several years has been, directionally, all the same, which is that people are becoming more concerned about the information on climate change and more determined to tackle it. Even in some countries where there have been two steps forward and one step back, there has eventually been another step forward. I am thinking of Australia, for example. The actions that are being taken in Asia are really quite significant. The Chinese are really moving in this area. So we are either going to grow these industries and deliver on low carbon here, or we are going to find ourselves having to deal with these issues, because of the evidence, but we’re going to be buying the equipment and services from other people who have seen the advantages of giving a clear policy steer and moving forward.

But I do think that the pace needs more detail around it than we currently have, and there needs to be an early move to give information on the issues that are not yet covered, to deliver the White Paper on time and to avoid more of a hiatus in investment than seems inevitable.

Christina Grumstrup Sorensen: I think, in general, there is high confidence from an investor point of view. We are seeing pension funds and private equity funds entering into the offshore investments, which we have not seen before. The past 10 years have shown us that this climate, the carbon emissions targets and the need for a low-carbon world is the right direction. Investors also see that.

We should see it as an opportunity. We are, as I said, using or deploying all the available technologies right now. We are building up a supply chain and creating new jobs, so we should think of it as not only a cost, but an opportunity.

Adrian Haworth: Just to re-emphasise, we truly believe that the UK has the best platform in the world to launch offshore wind. It would be a great pity if we lost that initiative by just not moving quick enough.

Q227 Albert Owen: What impact do you think the EMR proposals will have on supply-chain investment? Mr Haworth mentioned technology. Are people queuing up to be part of this?

Adrian Haworth: I am not sure that we all fully understand it yet. We believe EMR is going in the right direction. We are trying to understand how fast this market is going to move. Therefore, we could ramp up our investments in the supply side-it is not just primary supply side but also secondary and tertiary supply sides. Obviously we believe that the UK is the place to be because it seems to have the biggest opportunity for offshore wind. But there are other places that are developing. There were recently announcements from France; there have been lots of announcements from Germany and so on. We think that if there are delays in the UK, that could compromise the potential for investment in the UK because we will be almost forced to take opportunities elsewhere, which will often necessitate having sourcing locally there. Secondary and tertiary sourcing will be lost from the UK. That is why it is necessary to forge ahead right now and ensure that no hiatus is caused by the EMR. We think the EMR is the right direction, but if it causes a hiatus, that will be very negative for the industry.

Q228 Albert Owen: That is a very neutral answer, if I may say so. Do you think that prior to the EMR, there was confidence for the supply chain, and that it is now more difficult, from what you have seen thus far, for the secondary ones to commit themselves?

Adrian Haworth: I think we are going in the right direction. There are people looking-some people are here, but we have not all committed yet.

Q229 Albert Owen: We have had road shows and various things.

Adrian Haworth: We have. We need to understand right now that there are several other things taking place1, along with the EMR, which need to happen to give everyone the confidence to take the big leap-and it is a very big leap-into this marketplace. That is our position. Yes, we are going in the right direction, but speed and time are of the essence here.

Robert Cross: To echo that, timing is critical. We are not operating in a vacuum because other countries are implementing their own policies, and industries other than offshore renewables are also entering into these investment programmes. Equally as part of the EMR, the potential for pressure on this budget is quite significant if there isn’t clarity about how all this is going to work.

Q230 Laura Sandys (South Thanet) (Con): One of the things that we have heard from many of the people giving evidence is the importance of breaking the monopoly of the six big generators. Do you feel that the EMR allows greater openness for the market? What are the barriers that the EMR still does not address? What exact levels of investment do you feel that your companies can be making in the next 10 years? Have we got the framework to, in some ways, break the market open for companies like yourselves?

Christina Grumstrup Sorensen: As I started by saying, the market liquidity issue is not addressed as directly as we would have hoped for in the energy market reform. If we go for a feed-in tariff, it is difficult to see exactly how this index price would be framed. At best, you would have an intransparent price that you would then need to top up to make the feed-in tariff level. In the worst case, there could be room for price speculation. So we are very worried about the contract for difference, especially with an illiquid electricity market.

Robert Cross: It is not clear from the EMR consultation what the structure of the market will be in 2020 or 2030. You could have a situation where a significant proportion of the market is on some kind of contract for difference or on some capacity payment for balance and generation. I think they all in themselves will have an impact on the incentives for the generators and how they operate on a day to day basis, and I don’t think that is very clearly thought out in the consultation and how it will affect those of us that are looking to be in the market as part of our investment programme.

Joan MacNaughton: I agree with that. I would add that transparency is really important here. In principle, with the kind of market we have at the moment with six big players, that shouldn’t be uncompetitive. In principle, that is capable of being competitive and there are various studies that suggest it is pretty competitive, but more transparency would help, and it would help with liquidity. That comes back to the point that we’ve got to have coherence between these proposals and the liquidity review from Ofgem and the carbon price support mechanism review from the Treasury. There are all these different moving parts and they seem to be being handled somewhat separately but need to be brought together. We need to have visibility of how they are going to be brought together pretty quickly.

Q231 Chair: On the question of implementation, a timetable problem is already emerging. Given that the time scale for any project is so long, and the 2020 targets are so demanding, how late do you think we can agree the outcome of this consultation and still hope to attract the necessary investment in time to achieve our targets?

Joan MacNaughton: The later you leave it, the longer the hiatus in investment, and some of that investment will then occur elsewhere. We are in competition for that investment with other countries, because the investment goes wherever there is a good project with a good risk/reward profile. So I would put it the other way and ask, how soon can we do it?-can we deal with this as a time-driven project in order to ensure that we do hit the decarbonisation targets that we all think are important?

I do have concerns about the "taking one issue and then taking another issue" kind of approach. That has been very evident in relation to the CCS projects, which are taking far too long to bring through to award of contracts. Yet, they could make-they will have to make-an important contribution by the time we get to 2030, but if they are going to do it in 2030, you have to be rolling them out in 2020. That means you really ought to be thinking of starting the demos as soon as possible. That is one example of where you are not taking it as a critical-path-driven project but you are doing your consultation, your award process and everything else in sequence, so you are doing everything in sequence rather than driving it down a critical path.

Christina Grumstrup Sorensen: I think from an offshore wind perspective, in the system we have right now, we give evidence 3 years in advance of the current system running out in April 2014, so in April 2011 there should come out a new level for the ROC in 2014, so that time frame is okay-3 to 5 years. That is also why we don’t see an issue in having a staged approach, in having not to fix all 5 initiatives at once. It’s good that we know that all 5 initiatives will be in place, but we could move ahead with the market liquidity first, and some of the other areas, and then move further with the feed-in tariff once we have comfort in the market liquidity area.

Adrian Haworth: Some of the initiatives-for instance, the capacity mechanism-will be required as a consequence of other policies being successful; if the other policies are not successful, you will not need a capacity remuneration. Therefore, there obviously needs to be a concentration on the matters at hand that are important right now, and resources should not be deployed on policy that is not required right now. We don’t believe that the capacity mechanism is required right now and we don’t know whether that should be more focused on the supply side or the demand side. We don’t know how fast the demand side will be taken up, and we don’t understand exactly how much wind will be deployed or what the profile will look like that will need support from capacity mechanisms. Clearly, sorting out the FIT system is the most important for us right now, from a supplier’s point of view, to make our investment plans.

Joan MacNaughton: I largely agree with what both colleagues have just said. I think the worry would be that if you have a potential capacity mechanism-you know it will happen, but you don’t know when or how it will work-that in itself may stall some investment. You could argue that the capacity mechanism and the emissions performance standard do not add much to the package at the moment, but if they are always about to happen-on the shelf, about to be pulled off-and you don’t know what shape they will be or when they will be brought off the shelf, it will have a dampening effect on investors’ decisions. Having said that, I absolutely agree that one of the constraints here is the policy resource to get all the rather complex and difficult issues to the point where they need to be as quickly as they need, to be delivered.

Q232 Chair: Given the risk to which you referred of investment simply going elsewhere, which is perhaps compounded by a less regulatory regime in some parts of the world, higher growth economies and so on, I feel that there is a touch of complacency in much of the discussion here. I know we’ve got to get all this sorted out and it’s very important to get it right, so would it be helpful to have an early indication from the Government on some of these points, even before the consultation is complete, so that some of the uncertainties could be removed?

Robert Cross: I think that while it may be useful, it is also important to ensure that a sufficient impact assessment is undertaken of the changes being made, because the changes create quite a different structure in the electricity market, and those consequences ripple out to other markets as well. I don’t think that any early indications or commitments channelling the direction of policy should be at the expense of thoroughly understanding the wider implications of the market as it is changing. There are obviously markets that supply the electricity market, which will be impacted by the structure going forward, particularly the gas market.

Q233 Chair: There is particular sensitivity about the transfer from ROCs to FITs, where there appear to be particular concerns. Do you want to say more about that? I know that DONG particularly expressed views on that.

Joan MacNaughton: I just want to pick up on your question, if I may? Because this policy has so many risks and requires so much information that needs to be managed, maybe one needs a highly iterative process. Some visibility of some decisions on the consultation ahead of the White Paper could be quite good for testing some of the conclusions before the White Paper stage of what has been quite a traditional consultation document.

Christina Grumstrup Sorensen: On the transition from the ROCs to the FITs, we have no problem working with the FIT system; we work with it in other markets and are quite comfortable with it. The prerequisite is that market liquidity is working well. The energy market reform document sets out that ROCs will be extended until 2017. As I said before, we need clarity three to five years in advance, so that there is time to work through all the devilish detail to ensure that all the incentives put in place are working effectively and coherently, and supporting the objectives and aims that I set out.

Q234 Dr Whitehead: May I return to capacity mechanisms? You have mentioned that there is a potential problem of, as it were, a looming capacity mechanism not being there, but perhaps being there somewhere in the future. Because we can’t determine exactly what the future will look like, a looming capacity mechanism may be the best we will get. On the other hand, in terms of the various directives and so on, we know that a lot of plant is closing. Therefore, we can’t replicate in an automatic capacity mechanism the way that the market has previously pushed certain plants aside, and they then provide the back-up capacity.

Do you think that what the Government are putting forward about capacity mechanism is perhaps as good as it needs to be, in terms of indicating that there will be a need for capacity mechanism to keep the total amount of capacity available, and that that, therefore, should be put centrally into the system for the future?

Robert Cross: If I may answer first, with the capacity mechanism, we think it’s good to recognise that you need to have that balancing power available to the market when you are going to have, potentially, a great deal of intermittency on the grid. What we see as one of the concerns is that although that gives you the generating unit sitting there ready, the question remains as to where the fuel for that generating unit comes from. If you have the significant amount of balancing capacity required to suddenly switch on and then support intermittent load, that is likely to be gas-fired generation, which is the flexible supply source. You then have to find that gas in the system to suddenly meet that generation capacity. What the capacity mechanism doesn’t do is send that additional signal further upstream to where those supplies need to come from at short notice-either storage, or imports, or LNG, or whatever.

Adrian Haworth: It doesn’t seem to be clear exactly what the capacity mechanism is yet. The market is already handling the situation quite well, and given some adaptation, there could be a mix between new potential peaking capacity, if it’s required, or investment in the existing plant to make it fit for purpose as it changes its back-up role for renewables to demand-side measures that may be just as strong as supply-side measures. It is not clear yet what is required, and I’m not sure that anything in the document specifies what, in fact, the Government wish to drive forward. I am not sure that we know what is going to be necessary or what will be the best solution moving forward. Certainly, demand side is not very clear, but it is potentially very strong. The major concern for an investor would be the potential to subsidise peaking capacity and new peak capacity in the future that would threaten existing assets. I think that is what the lady from Alstom was alluding to.

Joan MacNaughton: Could I add to the comment that Robert made? There is one particular risk that hasn’t clearly surfaced, although it is there if you read carefully; a lot of coal is going to retire, and there is a clear intention that there should be no new investment in unabated coal, which is perfectly understandable. But coal plays an important role at the moment, and the question is whether you are going to have coal with CCS, and gas with CCS in due course, as part of your overall mix. Coal plays a particularly important role in the winter, when gas prices are high, which is when you see it providing quite a lot of our generation. That is when it becomes a very important hedge against gas price volatility. It is an important hedge for the country, rather than necessarily for an individual generator, because generators will hedge on their gas contracts.

I think some thought needs to be given as to whether there are enough incentives to invest in coal plant, when there is a clear signal that we are going to drive forward with CCS and allow coal with CCS to play a role in the system, as well as the very large proportion of renewables which we are legally required to do, the nuclear projects to which we aspire, and a lot of flexible gas. That would be a truly diversified portfolio, but as currently constructed I think the combination of these measures risks driving coal out of the system, or at least driving it to quite a small level and making us much more vulnerable in the winter. It takes away that intrinsic hedge against gas price volatility.

Q235 Dr Whitehead: What do you make of the so-called "slippery slope scenario", whereby if you have a capacity mechanism which is plant based, more or less, then the logic may look as though you do not invest in new plant outside that capacity mechanism, so that as the capacity mechanism unfolds, it comes to encompass all investment over a period of time, and therefore rather overthrows its own purpose. Do you think that is a realistic possible scenario for a capacity mechanism, or are there ways to avoid that? Are there other examples that may have occurred elsewhere?
Robert Cross: It depends on the detailed design of the capacity mechanism, which is not apparent as yet. But it is a possibility that you have, as I said at the beginning, a significant proportion of your generation on some form of support, be it the contractual difference or the capacity payment. I think that what that does is leave you in a situation where the market for providing generation is very much altered, and it is difficult to see how you would fit unsupported generation in that mixture. I think it is certainly a potential, but it is difficult to say exactly without having more detail about the capacity payment mechanism.

Q236 Dr Whitehead: Is that view held by everybody?

Joan MacNaughton: I agree. I do not think that we have seen examples of where capacity mechanisms are confined to very specific circumstances. I agree with what Rob has said.

Q237 Ian Lavery: You mentioned the coal and carbon capture and storage and the need to look at the energy mix in the future. How critical in your view is coal and carbon capture and storage in the future energy mix of the country?
Joan MacNaughton: I think it is critical. If you look at the Government’s 2015 road maps, it is envisaged that there is going to be a lot of fossil fuel generation-gas and coal-and that you therefore need to develop CCS. The International Energy Agency says that if you attempt globally to get to 2050 without applying CCS to power generation, then it will cost you 70% more than with CCS. That is not specifically a coal point. But if CCS works I cannot see why you should not be applying it to coal equally as to gas. In fact, given that coal reserves are highly abundant-they are well diversified across stable countries as well as in some less stable parts of the world-I do not see why you would deny yourself use of that resource. Indeed we know that there are a lot of countries that are not going to deny themselves access to that resource. This is going to happen globally, and I cannot see why the UK would choose not to take advantage of that particular technology and fuel mix if that is really what is going to happen globally.
Robert Cross: One of the issues I would see with coal particularly is that whereas there is an issue with the transition aspect of it, from the older plant to the new abated volumes, the difference with gas is that you can still make a lot of your contribution towards meeting your carbon reduction targets by unabated gas to which you can then apply CCS. Whether there is enough in terms of developing both of those together after 2030 depends on what happens in between.

Q238 Dr Whitehead: On capacity mechanisms and plants, the assumption that a number of people have been making is that any capacity mechanism, looming or otherwise, would be plant-based. That is effectively underpinning new plants, for example to replace standby oil plants as they have gone out of commission. There have been a number of suggestions that a substantial element of the capacity mechanism might consist of non-plant-based measures such as storage and substantially increased use of interconnectors-assuming there is something on the other end of the interconnector when you are connecting. Indeed, suggestions have been made that new players might be able to come into the market to aggregate demand-side measures, which then effectively operate as capacity mechanisms and could actually come into the capacity mechanism itself. Have you thought about those particular suggestions in your companies and organisations? Do you think that they could play a role in what may turn out to be how the capacity mechanism works?

Christina Grumstrup Sorensen: We certainly believe that all of these levers must be applied in the future electricity system, as they are also in other markets. Some of the means are not yet fully developed on the demand-side management and we should really embrace this opportunity to develop these things. We will not be able to know exactly what will be available 10 years from now, so solving it on a 10, 20 or 30-year horizon with all of these mechanisms not at hand right now could be dangerous.

Adrian Haworth: I would absolutely echo that. Some of you have visited GE’s Smart Grid Centre in Bracknell, which we are very proud of. I think we see a really strong future for demand side. We don’t really know; it is an evolution, but the UK is one of the world’s leaders in this evolution. We think there is very big potential on the demand side but we can’t quantify it yet, so it would be very difficult now to try to define where we will be in 20 or 30 years when we are really stepping out into the unknown at the moment. Definitely there is supply-side opportunity. There is so much interest in storage mechanisms right now that that would also be very interesting. On interconnectors, and on supply side and various ways of making that supply side responsive to what the needs will be in the future-which again is somewhat unclear-we think setting a rule now for what the capacity mechanism will be is premature.

Joan MacNaughton: May I add two points? First, more connectivity definitely reduces risk and helps with cost, but one needs to be a little bit careful that we don’t interconnect to take a lot of high-carbon generation from other places. That’s slightly self-defeating in terms of the goals of the policy.

The second point is on efficiency: how effectively you manage your dispatch, your management of your power generation assets, efficiency at the supply side, the whole transmission piece and demand-side response driven by smart meters, among other things. All of those are important. We have begun to move down the road on smart meters, but I think we need a coherent approach to the whole smart power piece, involving the storage, the dispatch, managing the intermittency, managing the likelihood of intermittency with different weather patterns very close to time and managing the transmission losses. Those technologies are beginning to emerge, and what we need to do is think about just how we incentivise getting them all in place. That’s another important interaction with the current proposals and one that Ofgem has under its purview in the RIIO proposals, which I think in principle are quite promising.

Q239 Dr Whitehead: That suggests that you might take the view that in terms of existing EMR consultation and what we know the pillars will look like, demand-side measures are perhaps not as present as they might be-or at least the co-ordination of demand-side measures to balance the overall market mechanisms. Is that your view or do you think that what is in the EMR at the moment, and the development of the various measures on grid-smartening and smart meters and so on, will do the job?

Joan MacNaughton: I come back to my initial answer. It is quite difficult to tell. It depends on how you design some of these individual instruments. They contain the potential for getting hold of some of the demand-side response, for allowing some of the new models of how you manage these issues to emerge, but it is not exactly clear how and at what pace that will happen.

Adrian Haworth: Right now I think the system works with the STOR (Short Term Operating Reserve) arrangements and other arrangements with the grid. We are not clear why an extension of that right now would not leave a level-playing field for these technologies to compete and sort themselves out. I am not sure that they need interference right now. I think people were looking to 20 years hence and a very spiky supply curve and thinking that we need to do something. But we are not there yet and we don’t understand what it will look like in the future. So right now I think that enhancements to the grid’s operating mechanism will suffice.

Q240 Chair: You mention the need to avoid interconnecting to sources that are high-carbon, but in practice there is no way of controlling that, is there? Okay, if we interconnect to France at the moment all that is nuclear, but if we interconnect somewhere else and they decide to have a lot of high-carbon generating capacity, we are stuck with that, aren’t we?

Joan MacNaughton: Yes; you can’t label the electrons. But if you are going to factor in a certain proportion of interconnection you can be very conscious of what you are doing to your mix by implication. So, I come back to transparency and being very clear about what it is you are trying to achieve and what the impacts of your measures will be.

Q241 Chair: I can see that interconnection might be beneficial in terms of security and price, but it couldn’t be a sure-fire way of guaranteeing progress towards low carbon.

Robert Cross: One of the things that becomes apparent with the carbon price support is that you can cover generation of carbon within the UK but when you have interconnection, you can’t apply the same rules to the electricity that is brought in. That is one the problems that we see with that.

Q242 Laura Sandys: I am just trying to turn it around a bit. Is there any way in which one could incentivise the capacity issue to penalise companies in distribution if they have to access additional capacity? In many ways one is putting the emphasis on the demand side and pushing companies and generators to look at better management and to incentivise them to ensure that consumers are managing energy more effectively. Instead of paying extra for this capacity, could we penalise for the need for extra capacity?

Adrian Haworth: I think the market does that now. To a certain extent the pricing in the market already addresses that issue. Peak-time electricity is more expensive than non-peak-time, and it is in the interests-

Q243 Laura Sandys: But the consumer ends up paying for it.

Adrian Haworth: Yes, but-

Q244 Laura Sandys: Whether one relays it on to the generator or not.

Adrian Haworth: This is all part of the smart grid evolution. Part of the idea of the smart grid is to solve the problem that you are addressing. If you are paying real-time prices for electricity, you will modify behaviour. That is the theory. I am not sure that that is the whole goal here. It may not be the householder himself, but maybe a co-operative of householders, or however it evolves, will manage the demand side based upon pricing. That is the ultimate goal.

Q245 Laura Sandys: Let me continue on the different subject of international comparators and international investment models. Are there markets out there that are more attractive for investment? What elements of the market regulation do you find particularly appealing, or offer you longer-term opportunities in different areas that we could learn from?

Adrian Haworth: From a supplier’s standpoint, we are obviously driven by customers. We don’t self-develop generally-we are not a utility, we supply equipment to utilities and other independents. We are where the markets are moving the quickest, so clearly a market that has defined the way it wants to go and is attracting investment is where suppliers will focus their attention.

In the UK, we see that offshore has everything we need for a supplier base-it has the skill set, it has the training, it has the ports, it has the continental shelf, it has the wind-it has everything you need to lead, but if there was activity elsewhere that was going to happen sooner, it would be attractive to us to play in that market first. We all want to get experience and we all want to be early in the market, which is why time is so important. The UK has all the ingredients, but if other markets are moving for other reasons-whether that is due to feed-in tariffs or other mechanisms-and are more attractive to the people buying our equipment, then we will follow them. That is just the way that our shareholders drive us.

Joan MacNaughton: I agree with that; I would just mention the importance of consistency and predictability. Traditionally we have had a very clear regime-very market-oriented although it has always been regulated-and people have had confidence in the stability of the regulatory framework. We have had some very large investments in infrastructure over recent years, and in plant we don’t have a problem with reserve margin at the moment. If investors feel that they have a predictable and stable regime and there is a consistency of principle then they will be drawn to invest. You have a problem if you are chopping and changing every few years-trying this, you don’t think it works, trying that, you don’t think it works-so it is important that we understand the principles and criteria that will underlie some of these mechanisms, and important to know that they will persist.

Q246 Laura Sandys: What other markets would you say are at the top of your list for investment due to their regulatory framework and management of the electricity market? What could we learn from them?

Joan MacNaughton: Again, we are a supplier and it’s down to customers, so I agree with Adrian. Actually, I think the UK has traditionally been a very strong market from that perspective.

Christina Grumstrup Sorensen: From a generator’s point of view, we have invested heavily in the UK in the past two years-offshore wind farms in Gunfleet Sands, Walney and London Array, where we are majority owners. We have done that because we have confidence in the UK regulatory framework. I very much agree that rocking the boat should be done with great care and implemented in a good way. I think the industry now needs stability, predictability and a long-term planning horizon. That is why we argue so heavily against the auctioning process, because that will be a major step back in the long-term planning of offshore and will not serve the aim of bringing down costs, bringing in new investors who have not been in the offshore industry before, or developing a supply chain.

Robert Cross: To echo those points, Statoil have chosen the UK as a market to invest in already, and I think that is reflective of the support mechanisms that are currently in place being sufficient for those projects. I think it is important that future support mechanisms retain some of that auctionality for investors to be able to manage their needs in exposure to the market. The current renewables obligation gives you a bit of certainty and a bit of market exposure, whereas some of the other mechanisms that are proposed in the EMR might not give you that same flexibility.

Q247 Albert Owen: Sticking with the point that was raised by the Chair about integration with Europe and the interconnectors, how much interconnection do you think the UK will have from neighbouring Europe? Do you think that brings associated risks with it? What is the balance? At the moment, it is very low; we just have the nuclear coming in and the Irish connection. How do you see the market developing? Does that pose risks for the United Kingdom?

Joan MacNaughton: I would just repeat that I think, in principle, more interconnection will reduce risk rather than increase it, because you have more choices about how to manage your supply and demand balance. Peak demand is at different times. You will have intermittency factors operating in different ways at different times. If you add together the large nuclear component that is France and even the storage from hydro that you get from the Nordic countries, you have, in principle, a very diverse mix. At the moment I cannot, therefore, see reasons why it would necessarily add to the risk-assuming that it is built to all the right standards, which we do.

Adrian Haworth: Clearly, more interconnection would help the renewables build out, but I think there is a limit to how much you can get in any case. So I don’t see that we’re going to be wheeling power in from China to the UK. Once you get to a certain point, you start merging peaks, so there’s really not much point in having an interconnection. It is limited, and I don’t think it’s a threat to the UK. It can only be an enhancement to the UK situation.

Robert Cross: I think it will improve security. The other thing that you have to look at is that there is a European framework within which the UK electricity market operates, which is meant to be driving us towards a single European market. The structure of that market will be important in determining power prices in the UK.

Q248 Albert Owen: So if we get that harmonisation, will some of the issues that we have been discussing as a Committee, such as emissions performance standards and raising the cost of British electricity, provide some sort of risk that people will be buying cheaper and maybe dirtier electricity from Europe?

Robert Cross: I think that is why the policies have to be aligned with those of other countries and why there has to be an effort, on a European level, to make sure that countries are trying to move towards the same goals and objectives in the same way.

Q249 Albert Owen: What would be your advice to the Government on EPS?

Robert Cross: From Statoil’s perspective, we replied to your emissions performance standards consultation and said that we didn’t think it was a necessary tool at present and that it may, in fact, draw resources away from investment in things such as CCS, because it basically stops you from investing. It may be something that you want to introduce at a later date, but it is almost as bad to have it hanging over the industry than not having it there at all. We would probably not see it as the best option.

Joan MacNaughton: Just on that specific point, I can see a case for certain forms of EPS or for an EPS that is, as your report on emissions performance standards set out, surrounded by an appropriate package of measures to incentivise CCS. I don’t think that the current proposal actually does that, and I don’t think that it is going to drive CCS. In fact, it will drive a lot of unabated gas-grandfathered under the current detail of the proposals-which means that you’re going to have higher emissions in the late 2020s than you would without it. So I don’t think that the current EPS proposal is either right in itself or necessarily surrounded by the right package of measures. I think it is quite a risky proposal.

Adrian Haworth: We don’t have any comments. We don’t think that it’s a major piece of the current legislative effort, and it is not necessary at the moment.

Chair: Thank you for your help. I am sure we will be in touch again.

Examination of Witnesses

Witnesses: Mark Ripley, Regulatory Frameworks Manager, National Grid, Jeff Chapman, Chief Executive, Carbon Capture and Storage Association, and Tony Glover, Head of Press and Public Affairs, Energy Networks Association, gave evidence.

Q250 Chair: Good morning. Thank you very much for coming in. I think you probably heard most of the earlier discussions.

We have a situation where the Committee on Climate Change has recommended that the carbon intensity of electricity needs to fall from its present level of about 500 grams per kWh to 50 by 2030. DECC’s modelling for the EMR consultation document is based on achieving 100 grams per kWh by 2030. How much more difficult would it be to get down to the CCC figure of 50 than just to go for the DECC figure of 100?

Mark Ripley: Getting down to 50 requires more radical solutions. We have been talking about decarbonising the current power market in terms of 2020, but in fact you need a step change with what you are doing with electricity to get to the 50 level, which means you need to have electrification of vehicles on a large scale, and you need to have an overall improvement in energy efficiency with a drive to more efficient lighting-LEDs, that sort of thing. You also need a very broad church of generation: you do need nuclear and renewables, but you also need CCS as part of that. It is big solutions for getting down to 50 for 2050, rather than the steps you need to take to decarbonise the current market.

Jeff Chapman: It probably means that we will have to a lot of biomass co-firing with CCS, so that we can operate open-cycle gas turbines for peak lopping, and compensate for that as well as the inevitable residual CO2 emissions from fossil fuel with CCS. We can do that: we know we can burn biomass and we know we can capture CO2, so we can do biomass with CCS and that will shift the average downwards considerably.

Tony Glover: Obviously it is an incredible challenge just to 2020, but to 2050, we are talking about a major challenge, as many of your witnesses have been saying. Another key area will be along the lines referred to in the previous session, about the role that demand-side management will have to play. Mark referred to efficiency measures, but in the next 20 to 30 years, we have to change fundamentally not only the way we use our energy, but the way we manage it and the way the network operates. We will no doubt come on to it later, but the idea of a virtual power plant as almost an alternative generation source is going to be crucial in terms of aggregating locally generated energy.

Q251 Chair: What does all this mean for consumer prices?

Tony Glover: From a consumer point of view, there are some major opportunities-for instance, with the development of smart grid and demand-side management. We are looking at major investments, but we can reduce the level of those investments if we manage that process effectively. Ofgem has talked about a £32 billion investment in the networks over the next 40 years, but we at Energy Networks Association are working with Imperial college and others on ways of reducing the level of network development that will be needed and on how demand-side management may reduce the level of cost to the public while meeting low-carbon targets.

Mark Ripley: Building on that point, I agree with Tony. Unless you have the control structures in place, costs will go up. If, for example, we were in a world in which there was large scale electrification of vehicles and people just plugged them in when they got home from work, all you would be doing is increasing the peak and increasing the need for generation capacity. You need the smart grids and smart metering technologies to enable time-of-use tariffs and to be able to use energy at the right times to minimise your overall peak and to drive down costs in terms of plant availability.

Jeff Chapman: When we get to 2030 and we’ve achieved 100 grams C02 per kWh or 50 grams C02 per kWh, the consumer will really need to know what that is costing. Openness and transparency will be very important, not only about the costs of generating clean power, but the cost of providing back-up support for intermittent supplies. We will be providing the consumer with a higher added value product-in other words, electricity without emissions-but we need to be absolutely clear that that will cost more, not only because it is carbon-free, but because of the need to deal flexibly with the supply.

Q252 Chair: Looking at gas and at gas prices in particular. DECC has made some assumptions about gas prices, but supposing that we discover that shale gas is recoverable and usable without difficulty and without damaging anything else and, therefore, gas prices are much lower, does that undermine the whole set of assumptions? Will it be much harder to get investment in low-carbon capacity?

Tony Glover: Yes, at Energy Networks Association, we commissioned research. We are not a gas organisation as such, but our members are network operators in both gas and electricity, so they have an interest in that infrastructure-to which, I might add, we are connecting 100,000 new customers a year. Lots more people want to be connected to gas. We are renewing the network in a multibillion pound programme of which we’re all aware out on the streets to replace cast iron with plastic. This is a very big infrastructure and probably one of the most comprehensive gas networks in the world.

We commissioned research from Redpoint Energy, which has been doing a lot of work with Ofgem and DECC. The research paper looks at the future role of gas, and in certain scenarios we could be looking at up to £700 billion of savings over the next 40 years while meeting the low-carbon targets, where gas will play a role. That points towards there being a role for gas in future while meeting the low-carbon targets. We could be looking at £20,000 of savings per household over the next 40 years while meeting all of our other objectives.

Mark Ripley: In simple terms, if the price of gas falls, gas generation becomes attractive from an economic point of view; you would therefore expect more people to build. The contract for difference would therefore play a greater role in underpinning renewable sources compared with the wholesale price. Gas would get you to the 2020 targets, and there are arguments that it is cheaper than some of the other options, but it won’t get you to the 2050 target of 50 grams C02 per kWh. Although gas has a role in the long term transition, it would need to be abated gas rather than the combined cycle gas turbines as we know them today.

Q253 Chair: If we had lots of cheap gas, I would question whether we would electrify heating. If you as a consumer can buy your gas very cheaply and conveniently, why would you switch to electricity? Yet both the Committee on Climate Change and DECC assume that the electrification of heating will happen before 2030.

Jeff Chapman: To achieve the 80% reduction target overall you would still need to provide heating by carbon-free means, and gas heating would obviously contribute to emissions. We at the CCSA are a bit agnostic about which form of fossil fuel to use-we are here to promote CCS-but we observe the fact that the current arrangements appear to work very much against coal and we are concerned that coal has been regarded in the past as a strategic part of our generation mix. Big piles of coal are the best possible energy store, and certainly the cheapest possible energy store when you compare it with, let’s say, underground gas storage. We may well be missing a trick if we vest all our faith in cheap gas, which might not quite deliver.

Q254 Ian Lavery: Looking at the network impacts, the investment in the upgrade of the energy market is estimated at more than £200 billion-that is Ofgem’s estimate. Of that £200 billion, I think £32 billion needs to be in the energy networks themselves. How will electricity networks need to change to enable the transition to a lower-carbon energy-secure system?

Mark Ripley: We’ve talked about smart grids and smart metering in terms of grids that are able to facilitate two-way communication for time-of-use tariffs, which enables us to access more of the demand side. We will need to invest; National Grid has a £20 billion investment programme outlined, largely in the electricity transmission system in Great Britain to keep it fit for purpose for a change in generation mix.

Tony Glover: Massive investment is required at transmission network level-National Grid level-but there will also be a lot of work at the distribution network, local level, involving the regional companies. Traditionally, the network at local level has been passive-it’s been one-way, rather like the wiring system in your home-so it is not being managed actively. That clearly is going to have to change. There is the idea of what is called a distribution system operator managing that local network in an active way, and distribution network operators playing a very different role to the one they currently play in order both to manage the microgeneration and to ensure that increasing penetration of things like electric vehicles and heat do not have an adverse impact on the network. This is clearly a very big challenge. The previous Government and this Government and Ofgem have been developing the low-carbon networks fund, which is a fund to provide up to £500 million-worth of investment in basically thinking about projects that will make the network able to manage this process more effectively. We strongly welcome that; we think it is a very valuable thing and at ENA we’re co-ordinating the various projects that distribution network operators are undertaking. One of the really good things that have come out of this process-something Ofgem has recognised-is that this is a very collaborative approach, with distribution operators working with others in the renewable heat sector and the electric vehicles sector. It is a very collaborative process, but there is a lot of work to be done.

Jeff Chapman: Transmission networks were put in place to get the power from where it was generated to where it was required. Historically, a lot of power was generated in places like South Yorkshire because there was a lot of coal there-"coal by wires" would be an expression. In the world of CCS, another factor will come into play: we will want to ensure that we build fossil fuel power plants close to the shoreline to get the CO2 quickly offshore and inject it into reservoirs under the North sea and the Irish sea. Largely, that probably maps on to existing arrangements, but we will have to bear in mind that CCS in future will bring about this change-well, it may not be a change of requirements too much, but there will be a demand for putting power stations on the shoreline.

Q255 Ian Lavery: An awful lot of new capacity is required for the future. Is £32 billion enough?

Mark Ripley: It might be. Ofgem presented a series of ranges in its discovery document. You can come up with scenarios that would involve spending more than that, and you could come up with scenarios that would involve spending less than that. By way of example, a lot of investment is required in offshore wind subsea infrastructure. We have done analysis that said that if you had possibly a more integrated approach where you created subsea motorways which linked into the offshore wind, rather than a multiplicity of connection points coming inshore, it would save something like £4 billion to £5 billion and would probably obviate a number of difficult planning issues.

Tony Glover: One of the important things to remember is that in terms of the customer’s bill, the network component is comparatively small. It is 17% to 18% of the average household bill-£60, £80 or whatever-so when we talk about the level of investment that is required in the networks to make the rest of the system operate more efficiently, we are looking at a proportion of something that is not gigantic in the general scheme of things. To be quite frank with you, we get very good value for money from our networks in terms of their efficiency and the service that is provided. Yes, there will be an increase in what the public have to pay, but in the grand scheme of things it is very good value.

Mark Ripley: May I echo a point from the previous session, when one of the panel talked about the knock-on effect of gas, but from a supply perspective? If gas, as is largely predicted, will provide the substitutable power source for wind-wind being not as reliable as a resource due to the weather factors we all know about-then we may see a need for gas stations to come up and down relatively quickly, more than they have done so far. The national transmission system was built on the basis of largely UK continental shelf supplies flowing north to south with fairly flat deliveries. Over time it has evolved, but it will need to evolve further both to meet changing supply demand, with significant amounts of LNG coming into the south of the country now, and changing use in terms of CCGTs coming up at relatively short notice, perhaps in short periods of time.

Q256 Albert Owen: You talked about the subsea network. How developed is that and how large are the savings it can make? As all three of you rightly said, we will now generate in non-traditional areas. Most of it is under the sea and there is offshore wind, obviously, and new nuclear on existing sites will have increased capacity. How advanced is that? Secondly, how much will it impact on household bills if there are subsea and underground networks as opposed to traditional pylons across land? It might be a lot of money for the actual infrastructure, but over a period of time, how much will that mean to the consumer in electricity prices?

Mark Ripley: Subsea technology is relatively well established. We have subsea interconnectors in several places around the world. It is largely an efficiency point that we are making.

Q257 Albert Owen: Who makes that decision?

Mark Ripley: That is an Ofgem-driven model for offshore generation. I think there are a number of players in the market who are quite keen to have a debate about what is an efficient outcome. Some players will compare and contrast that with wanting to get on with it, which is a legitimate trade-off to make. Certainly we have done analysis to show that there are potentially significant savings in going to an integrated model, which would not necessarily have to be as you built it. Obviously, we would have an interest in that as a transmission company, but there is a sort of self-evidence about an integrated plan rather than a piecemeal plan.

In terms of the onshore costs, you mentioned undergrounding, which typically costs somewhere between 12 and 17 times what it costs to overground. Those figures are reasonably well known. We operate under a regime where we are rightly incentivised to be efficient and economic in what we do, and while the transmission component could be argued to be relatively small, it’s important that all components are looked at with a cost-management perspective to ensure the best result for the end consumer. As we have said, we would be happy to engage in a broader societal debate about overgrounding, but we work under the regime that we do.

Q258 Albert Owen: Do you want to add to that, Tony? How much do you think it’s going to cost the average household? You’ve got all these other simultaneous targets such as the capacity, as we have just talked about in the previous session, and the need to get the investment in. There are aesthetic reasons why people don’t want pylons, but there is a practical element here, especially if you tell people in advance.

I was a bit concerned when you said that you’re having a debate. Really, we should be getting on with it, shouldn’t we, rather than having a debate about this? The consumer should be all the wiser knowing exactly the cost differences in putting it underground, and what that’s going to cost on their bill for the next 30 or 40 years.

Tony Glover: As I said, in terms of the component of the bill, that gives you an idea of the level of investment. This is still a smaller component of the bill than other aspects, and it’s good value for money. Mark’s referring to the whole issue of undergrounding, for instance, and quite clearly it’s 17 times-

Q259 Albert Owen: That is the initial cost.

Tony Glover: Yes, that’s the initial cost, which is incredible if you look at the kind of lengths that we’re looking at. Rightly, Ofgem has delivered over the last 20 years a highly cost-efficient model for the industry, which is very efficient and able to deliver far more for far less. We’re regulated very strongly, and quite rightly so. That’s the way it should be.

Undergrounding has to go through that rigorous process as well. Having said that, all our member companies at both the distribution and the transmission level are obviously working with people such as the AONBs, and there are now incentives through Ofgem for undergrounding in specific areas of outstanding natural beauty. Obviously, this is a sensitive area, but work is going on. It has to be justifiable, however, because we are looking at considerable increases in cost by undergrounding over very long distances.

Q260 Albert Owen: So you can’t tell me how much it’s going to be overall?

Tony Glover: I can’t tell you exactly, no.

Q261 Albert Owen: One more point, if I may. There doesn’t seem to be much joined-up thinking here between gas and electricity. For instance, in west Wales they have had a fantastic project involving the undergrounding of a gas pipe there, and there is now talk of pylons, possibly, or another way of bringing electricity from the west coast of Wales across to large conurbations such as Cardiff.

Why don’t you all sit down together and say, "We could put a cable in here and we could put some broadband in to follow"? It’s a serious issue that I’m raising here. Rather than having massive planning debates and so on in the future, if we’re talking about the huge capacity that a colleague raised earlier surely we can have that sort of foresight so that disruption to the landscape can be kept to a minimum.

Mark Ripley: While I’m not on the practical engineering side of the business any more-I’m long out of date in that aspect of it-there are some practical engineering safety considerations about running high-voltage cables and high-pressure gas pipes in very close proximity. While there is some scope to do that on a distribution level in a high street, in terms of a pipeline that’s running at 94 by gauge, in the case of the south Wales pipeline, that brings its own particular engineering challenges.

Q262 Albert Owen: So it’s not practical?

Mark Ripley: I believe that’s the case, although it’s not my actual area of expertise.

Q263 Chair: I want to go back, Mr Glover, to what you were saying, which is the characteristic industry defence of its insistence on using 1950s technology for transmission rather than looking at something newer. That argument drives a complete coach and horses through the "polluter pays" principle, because overhead transmission lines pollute landscapes occupied by a small number of people in order to keep costs down for a vast number of other people who live somewhere else.

In every other aspect of planning and decision making in relation to this industry, we accept that the polluter pays. If we want to put up a great big coal-fired power station next to a housing estate, you would expect to see some objections which we would pay attention to. Why do you think we abandon the "polluter pays" principle when we deal with overhead transmission lines?
Tony Glover: The reality is that everybody has to pay. That is the reality of this. The polluter is the public, in a sense, because it is the public who is getting the benefit of the network. Of course, work is going on-National Grid is working with the IET and looking at undergrounding, and at various technical options to improve the way that operates. To say that we are operating 1950s technology-we are actually looking at developing that technology-
Chair: Overhead transmission lines do not seem to have altered very much in the last 60 years.
Tony Glover: That’s what I’m saying. There is work going on at the moment on this very point.
Chair: It’s not going on very fast. There is no other aspect of this technology which is still using 1950s technology-no single other aspect. You are quite keen on these smart meters and smart grids and so on, which are actually more expensive than the old ones-but we do that for a purpose.
Tony Glover: We have been going through a period where there has been a real pressure on costs. The industry was privatised and a lot of work was done to reduce costs. But work is going on at the moment and I think it is fair to say that, right across the industry, nobody underestimates the importance of the impact of our infrastructure on the public. There is a lot of work on community engagement-

Q264 Chair: Let’s be clear. Your proposal is that the polluter should not pay in this instance. The extra costs of avoiding the pollution are not costs which you think the polluter should pay?
Tony Glover: I think they need to be quantified and I think that’s probably a matter for the regulator.

Q265 Chair: I’m asking about the principle. We can discuss the quantity afterwards. You are saying that the polluter should not pay the costs of avoiding the damage done to a certain number of people in very beautiful landscapes? Is the industry view that those costs should not be borne by the polluter?
Tony Glover: Certainly, but no, I think the principle is that the public will have to pay what is generally agreed to be the level of cost that people are prepared to pay to address this issue. But make no bones about it-when you say "the polluter", it is the public.
Chair: Yes, but you said the polluter pays. I’m saying that you are trying to justify your insistence on 1950s technology by saying that the extra costs should not be borne by the polluter.
Tony Glover: No, I’m saying that if the polluter, which is the public because it is done on their behalf, is to pay-if that is something that the Government and Ofgem feel should happen and that therefore a 17 times increase in expenditure on overhead lines should be paid by the public, then that will be the case. But that is not a matter for our industry. We are regulated and controlled in what we can spend and invest, so it is not something that is within our power. That is for the Government and for Ofgem.

Q266 Ian Lavery: Getting back to the development of the new networks, do you believe that the Government need to set out explicit goals in relation to the development of the new networks in that connection which will facilitate EMR, or do you believe that possibly it should be left to Ofgem and the market?
Mark Ripley: I think we would resist any Government central planning in this area. The regulatory and legislative framework that we have had to date has by and large delivered the investments that we need. We have been involved in a number of offshore initiatives-the North Sea Countries Offshore Grid Initiative, Electricity Network Strategy Group-all looking at what is required. Investment is coming forward. I do not believe that a central planning approach in terms of grid infrastructure is necessary.
Ian Lavery: So what would you suggest-the Government or Ofgem and the market?
Mark Ripley: The market.

Q267 Laura Sandys: Looking at the demand side, do you feel that the EMR really is creative and smart enough and creates the right incentives to look at the demand side in a much more fundamental way? Obviously, we have smart meters, grids and appliances, and there are also distribution networks. The Combined Heat and Power Association has said that there aren’t enough incentives to look at new models of how we utilise energy.

One other aspect, which is not in the EMR at all, is about how we help, work with and create a smarter consumer. Jeff was talking about lots of different mechanisms, and we need to ensure that there is the right environment transparency, which has been mentioned many times, as well as consumer information about what they are buying and at what cost. Do you feel that the EMR really covers the demand side enough?

Jeff Chapman: The demand-side proposals in the EMR remind me very much of what industry used to have in the way of interruptible gas contracts. You could take out an interruptible gas contract and be interrupted for a number of days-I think it was up to 30 days in the year-but you bought your gas for a lower price, so there was an incentive to take out such a contract.

In the electricity market, I think we can basically do the same thing. The corollary, of course, is that anybody who has an intermittent supply has a lower value of electricity, because that creates a problem. So, anybody who can be flexible should be rewarded, whether it is a consumer or a supplier, and anybody who is inflexible or intermittent should be penalised in some way.

Mark Ripley: We use demand-side services now as the system operator of the GB electricity market. We have contracts with a number of demand-side players for curtailing demand for short-term operating reserve, which covers off things such as forecasting errors, or unexpected plant failures.

We also have demand side for what’s known as frequency response, which is the first reaction to a generator falling off the bars, and therefore we have to take demand off to maintain frequency. They have proved very successful in that market, but by their nature, those energy products operate for very short periods of time. It’s not clear to us, with the current range of services that are available, that demand side could provide, if you like, alternative capacity to offset the wind not blowing.

If you think about the first two weeks of December last year, we had a big blanket of cold weather without much wind. At the moment, it’s not clear how demand would be able to step into that gap. That said, if we can develop in the future-as we have discussed-the smart measurement arrangements, smart grid arrangements and aggregator arrangements whereby peaks can be reduced, that will offset the need for capacity in the first place, which will be beneficial.

Q268 Laura Sandys: But, I think in some ways you are talking about demand from a supplier’s perspective. What about issues relating to consumption? Have we got the right levels of incentives? Do you see these new technologies actually changing behaviour? Of course, that is part of the equation because, otherwise, what we are looking at is just a huge increase in generation capacity, having to meet £200 billion in investment-and possibly more than that. If we don’t look at it from the demand perspective-and I mean consumption, not generation-it is different.

Mark Ripley: I agree, and that was the basis of my point earlier about the electrification of vehicles. Unless you have the time-of-use tariffs, all you do is add to the peak. You need to have innovative use of electricity for new purposes so that you manage that peak. That enables you, first, to use your wind generation at times when we traditionally haven’t had high demands and secondly, to manage that peak down as well. You actually manage your need for generation, because you have a well managed use at the supply end. That requires technology in terms of measurement and communication.

Tony Glover: To add to that, there are two issues, and I’ll use the example of electric vehicles, because potentially we are looking at a very large demand. They are talking about 1,300 additional charging points in London in the next year or so for the Olympics. That is very small-scale at the moment, but it could have a massive impact. There are two ways of managing that: the first is to put in lots more local wire, and the second is to have a smart network and manage that process more effectively. We believe that it’s absolutely crucial that, as we proceed on this incredible project of smart meter roll-out over the next few years, we actually ensure that that process, the design specification and the way in which those smart meters will operate are completely and utterly in line with, and will facilitate, a smart grid.

Going back a few years, when smart meters were originally looked at, they were just seen as a means for the consumer to understand energy usage and to manage it accordingly, but they have the opportunity and the potential to be far more than that. At some point down the line, it is possible-and we at ENA are looking at this and working with suppliers-that smart meters, in conjunction with smart grids, could develop a very complex network of demand-side management measures with multiple tariffs. That will actually probably have to be managed by some sort of ESCO or some sort of programme that will be able to manage that process so that the public are able to get the most benefit out of it.

Q269 Laura Sandys: But that really worries me, because what, in some ways, you are saying is that it is going to be an incredibly complex balancing system, and I, the consumer, am not going to be smart enough to be able to make the choices that I need to make to reduce my consumption-consumption at different times of the day, using different energy sources.

If we are going to change behaviour and the demand and consumption of energy, we-the Government and the industry-are going to have to design it from the consumer’s perspective. That means small businesses, not just households, and even medium-sized businesses. The complexity of this will merely create middlemen or wholesalers who will be packaging up and hedging the market itself.

Jeff Chapman: But we ought to discriminate between short-term peaks and the flexibility needed to keep the power on all the time. If you lose a lot of supply through intermittency in the typical few days of the anticyclone in January, you must have a lot of capacity sitting by to be able to fill that gap. That problem will get worse and worse. No matter what we are talking about with demand-side management, that is not going to fill that problem. It might contribute to the tea-time peak, but it’s not going fill those problems that exist over several days, rather than a couple of hours. We will be dependent on fossil fuels being flexible into the future-and, of course, they’ll have to be equipped with CCS.

In terms of the EMR, the capacity payment mechanism will be absolutely essential in that respect-not paying on capacity, but paying on flexibility. The word "availability" is touted and that is fine, but what we are really talking about is the flexibility to be able to deliver this. So there is a lot of devil in the detail of this mechanism. It hasn’t been fully thought out yet, and it needs to pay for the flexibility of supply.

Q270 Dr Whitehead: Jeff Chapman has said that a capacity mechanism is absolutely essential. Mark, you have said that, as far as National Grid is concerned, you are not convinced that a capacity payment system is necessary and that you might be able to deliver sufficient capacity through, in particular, sharpening imbalance payments, which sounds to me like continuing to whack supplies around the back of the head until they damn well go and build power stations. Is that how it works? How would you see that functioning as an alternative to what Jeff was mentioning?

Mark Ripley: Yes, we’re not persuaded that there is a need for a capacity mechanism. We have particular concerns about a targeted capacity mechanism, because it’s a slippery slope. You would find that capacity that wasn’t receiving a payment would either close or seek a payment, and, incrementally, you would end up with an across-the-board capacity payment. We did have a capacity energy split in the pool days where there were capacity payments and commodity payments, but we’ve been in an energy market for some time now.

Imbalance prices provide signals to market players about what the cost of their not having sufficient generation capacity is causing. At the moment, the imbalance prices on electricity are damped. They are very much an average of a range of actions that we have taken, rather than a marginal price at one extreme.

It is worth exploring whether a change in the imbalance arrangement would provide the right incentives on the supply market to ensure it has sufficient capacity available. In that way, you would leave the decision making on providing the right levels of capacity to the market, rather than a central focusing arrangement.

Q271 Dr Whitehead: You say there might be an exploration, but presumably in order to suggest that you have already explored how the system might work in more detail for the national grid?

Mark Ripley: We are supportive of more marginal imbalance prices to send the right signals to people of the consequence of their not having enough capacity available.

Q272 Dr Whitehead: Concerns were also raised about how you might specify the required functionality of whatever capacity there is. Linking to your statement on imbalance payments, how do you see the functionality, particularly in terms of Jeff Chapman’s points about the extent to which capacity measures might not be necessary just for peaking, but also for ensuring that an overall supply was available in a much more variable field? How would you see that specified functionality happening?

Mark Ripley: We wouldn’t want to prescribe what was required in terms of capacity availability because, as we have already discussed, there is a potential combination of generation availability and demand-side actions. Providing you send the signal to the market about the cost of capacity and availability, then market players-who will tell you that their business is risk-management-will be better placed than a centralised player to manage that risk and make sure they have sufficient capability available.

Q273 Dr Whitehead: A thought for everyone. I mentioned this question in earlier exchanges: to what extent might a capacity mechanism be forged, not so much on the basis of standby plants, but on the basis of interconnection? You mentioned not only demand reduction, but storage capacity as well-is that something that could present an alternative model, or would it be something that might stand alongside a largely plant-based mechanism?

Mark Ripley: I think it’s complementary. To go back to my point on choosing how you meet this need, interconnection has a significant role to play. I think connection to Nordic countries for pump storage was mentioned earlier, but also if you connect to the broader European network you are diversifying the risk of the wind falling away. The wind not blowing in Great Britain might not mean the wind not blowing in mainland Europe, and likewise you have your peaks offset. So if the market arrangements are compatible-and we’ve touched on that as well-we should see a freer transfer of power to countries as it is required.

Tony Glover: I think this was touched on in the earlier session, but the nature of the European market is being driven into a more liberalised approach, and we are encouraging that. Therefore, free flow and interconnection, as Mark says, can provide a serious contribution to our energy situation. Diversification is absolutely key to this, and I will come back to the point about electricity market reform, but we must bear in mind the important role that gas can continue to play, in terms of providing both a cost-effective and secure solution to some of our energy generation issues. When looking at electricity market reform one of the things that must be considered is the role that gas may play, particularly in relation to the fact that there may be numerous supplies which will impact on the cost. The public will begin to appreciate that fact, and that could have an impact on what energy sources they want, in terms of the choices they make and what is the most cost-effective solution.

Jeff Chapman: I echo the caution of Joan MacNaughton earlier, that if you are going to call for electricity from the European pool, it may well be high-carbon electricity that you are pooling. To extend what she said, it is more likely to be high-carbon because it will be fossil fuel at the margin.

Q274 Dr Whitehead: A related question that I want to ask is a simple one. If you have a substantially greater penetration of interconnection into the energy mix-both as a balance and I presume as a mechanism on some occasions to give basic output on days when our wind is not doing its ideal job-what level of interconnection might be reasonably feasible to look at? What percentage of the energy supply might be supplied by interconnection? Does that not lead to potential prisoner’s dilemma outcomes for Europe in terms of overall supply? If everybody in Europe believes that they can have interconnection to their particular energy economy, no one puts anything at the end of their interconnector. Therefore, you have a problem collectively across Europe of having a capacity deficit that may have to be addressed by other means.

Mark Ripley: In terms of percentages, I don’t know, I would be speculating, and I would rather not. In terms of the prisoner’s dilemma, if the markets are providing signals, people will face exposure to that imbalance. That is an incentive for building capacity. We are also talking in EMR about a packet of changes to provide incentives for low-carbon generation to build in this country. Therein lies the devil in the detail of getting the balance right on these interventions.

You made a point earlier about carbon linkage, on how you set the carbon floor price. We are much of the view that the carbon floor price should do little more than create a stable platform, which the EU ETS scheme is set out to do, but hasn’t delivered. Clearly, if there is a different price of carbon in European countries, that has an impact and is something that needs to be looked at, to try to make it work as it should have in the first place.

Q275 Ian Lavery: In the session prior to this, we touched briefly on CCS and coal. Looking at CCS and coal together, what impact might that have on the EMR? In your submission, Mr Chapman, the CCSA said that the EMR would inhibit investment in clean coal. Will you explain why you think that could be the case?

Jeff Chapman: Do you mind if I review the four pillars of the EMR? First, the FIT is the bit that is going to be doing the heavy lifting in this area. There is a particular problem with a FIT with a contract for difference, in terms of fossil fuel and CCS. While it is a very creditable mechanism-you get a guaranteed price for your carbon-free electricity-it isolates you from the fossil fuel market, so you are totally exposed to fuel market risk. We would recommend that the FIT, if it is a CfD FIT, should in some way be index-linked to fuel price. Obviously, this mechanism discriminates against coal, because coal is a much bigger proportion of the payment.

I have talked about the capacity mechanism, which is very important. The carbon price support definitely discriminates against coal, because a coal-fired generator is going to pay more carbon price support, even on the residual emissions after the CCS. If we get everything else right, the EPS is pretty well unnecessary. I’m afraid that it discriminates against coal because the Government have committed to four demonstration projects while at the same time saying that they will bring in an EPS of 600. If you are not one of those four demonstration projects, you won’t be building a new coal-fired power station, because you won’t be getting the support for it. The same thing applies to the existing regime under which, basically, you cannot build a coal-fired power station without demonstrating 400 megawatts gross of CCS.

Unfortunately, you have to compete in the area of CCS. In the past week nine projects have gone forward in a competition, which is incredible. It is absolutely marvellous that in the UK we have put nine projects forward, which probably equals the number of projects in the rest of the EU member states. But we will probably do only three of them, because out of the four we are committed to, one of them will likely be gas. So we will do only three coal projects at the most. That means that if you are not one of those three, you are not going to build a coal-fired power station, because you will be constrained by at least 600g per kWh, which would entail CCS. There is no mechanism in place at the moment to pay for that, unlike, of course, with the renewable obligation. As it stands at the moment if you want to develop a renewable plant-an offshore wind farm, or whatever-you know that you can get support for it; you don’t know with CCS.

Q276 Ian Lavery: If the electricity market reforms, which you suggest are anti-coal in some way, did prevent the development of new coal-fired power stations, do you think it would impact on new development of CCS technologies?

Jeff Chapman: Yes. It’s very important that, as Joan MacNaughton said earlier, we get CCS projects under way as quickly possible, show the rest of the world that we can do it and get out there and do some exporting. The EMR, taken as a package, is a mechanism that is focused on business as usual for mature technologies. Well, CCS is not mature and is not business as usual. It has a lot of first-of-a-kind costs, which break down as the additional technology costs for being demonstration projects.

The other element is the infrastructure, for which there is a huge first-of-a-kind cost. The Energy Act 2010 created a CCS levy that would have been an excellent mechanism for paying for first-of-a-kind costs over and above what the market would deliver, but, at the moment, that has been put on ice while the Government think about EMR. Fine, but we could have been getting on with it, and we can be getting on with it if we use the CCS levy for the purpose for which it was intended. If we don’t do that, we will have to find another way of covering those first-of-a-kind costs. I would suggest that a good way to do that would be to use the guaranteed revenue that HMT will get from the auctioning of allowances plus the carbon price support mechanism.

Q277 Ian Lavery: Thanks. The panel will be very familiar with the phrase "grandfathering". On the grandfathering of an EPS, do you think this approach is fairly risky? Do you think it would decrease the incentive to develop carbon capture and storage because, if it happens, there will not be any requirement to retrofit CCS in the future?

Jeff Chapman: Yes. If you build a 600g per kWh coal-fired power plant now, you will be grandfathered for the rest of your life. There is no regulatory incentive to refit later. The incentive will have to come from the package of other measures-the financial incentive through the feed-in tariff-and we had better ensure that the latter works properly for fossil fuel and CCS, otherwise we will be left without fossil-fuel stations and without the ability to respond flexibly with low-carbon electricity as will be necessary in the future.

Q278 Ian Lavery: I asked this question of someone in the previous panel: do you think coal has a crucial role to play, together with CCS, in the future energy mix of the country?

Jeff Chapman: I think it’s very important as a component of electricity supply to provide supply security.

Mark Ripley: As you said at the start, to reach the 2050 targets, we will need a significant amount of CCS generation, which coal can play a part in alongside gas.

Tony Glover: Just to add to that, as some of the gas network infrastructure becomes redundant over time-which it clearly will-that can also play a role, as can the expertise of that industry, in the CCS process, particularly in relation to coal.

Q279 Dr Whitehead: I wanted briefly to explore the question of the fact that in EMR we have a form of feed-in tariff essentially to drive preferences to low-carbon generation. On the other hand, we have investment in CCS, which simply makes possible generation by, for example, coal-fired power stations. But it does not give them any incentive other than that: that is to say, they would operate without a FIT. Would you suggest that a logical extension of that would be, as you seemed to imply, Jeff, that there might need to be some form of feed-out tariff post-CCS to give some sort of certainty for CCS investment beyond pilot projects, for perhaps gas-fired power stations in the future, and indeed coal-fired power stations which otherwise would not be built in a post-CCS world?

Jeff Chapman: I’m not sure I’ve come across a feed-out tariff.

Q280 Dr Whitehead: I’m sorry, I was going to say I’ve just thought of it. But it does occur to me from what you are suggesting that under a number of circumstances some form of additional mechanism may be necessary to secure the place of non-fossil fuel mechanisms within an architecture which, as you and other witnesses have suggested, seems to drive them out.

Jeff Chapman: I think so. Certainly to cover off this infrastructure issue, somehow a way has been found to finance the infrastructure demands of offshore wind, which we have talked about. We will have to find a way of financing the infrastructure needs of CCS in future. It will not come from just the demonstrations, because it is a local thing. If, for example, the four demonstrations turned out to be in Scotland and Humberside, you would not have provided any infrastructure for Thameside. In any event, at the moment, policy is not to provide any associated infrastructure that is sized for the future. That is a big thing that we really need to address. How did we get our sewerage system in place in the first place? Because that is what we are talking about: we want a sewerage system to dispose of CO2, and we need to find a way to finance that, which is not necessarily associated with CCS project-by-project.

Q281 Chair: It’s apparent, is it not, that to achieve the amount of generating capacity we need, we are going to continue to have some fossil-fuel element-coal and gas? It is also apparent that to get anywhere near the targets for emission reductions we cannot have unabated coal or gas. The Government tossed £1 billion on the table for the CCS experiment. How many bidders are there now?

Jeff Chapman: Well, the previous Government, if I can remind you-

Chair: Absolutely. A welcome reminder.

Jeff Chapman: They created the CCS levy and attached a figure of £11 billion, which they estimated would be raised to finance the four projects over their lifetime. It is a pity that we have ended up with a headline figure of £1 billion coming out of general taxation, because that immediately pits CCS against schools, hospitals and general social expenditure. Wouldn’t it be much better to say that fossil fuel power generators will pay a lot of money to the Treasury through the climate change levy-the carbon price support mechanism-and from the auctioning of allowances? The sum of these two things is a guaranteed income for the Treasury. The Treasury can predict what it will get.

Q282 Chair: I don’t disagree with that but let us put that one on side for the moment. My concern is this. We have agreed that we are going to burn fossil fuels and they can’t be unabated. The first of these four experiments for which £1 billion, from whatever source, is available has resulted in a position where only one bidder was interested in doing it. Aren’t we being incredibly complacent about the likelihood of carbon capture and storage being ready anywhere near in time to achieve the other goals? With all these incentives from the worldwide market for the first breakthrough in this area, the pessimism shown by the industry and the lack of enthusiasm are extremely striking. How on earth can we assume that we will have the technology to abate coal and gas generating capacity in time if there is so little interest in 2011 in doing the work?

Jeff Chapman: The competition we had for the first project turned out to be a process of attrition rather than competition and took an awful lot longer and was a lot more difficult. You can understand that many large industrial organisations got bored with the process and have gone elsewhere. That has happened. At the same time, out of the bids for the so-called NER300 funding from Brussels, the UK has pitched up nine bids. There is no shortage of enthusiasm for CCS in the UK at all.

Q283 Chair: Is there a project at Hatfield at the moment?

Jeff Chapman: I understand that the administrator is keeping the project alive in the hope that someone will find it sufficiently attractive to pay some money to it.

Q284 Chair: So, to summarise, we have only one bidder for the £1 billion available; we have considerable uncertainty about where the money will come from, notwithstanding your perfectly valid points about whether there will be any money to pay for the further experiments, assuming anyone is interested in them; and we have a busted project at Hatfield. That is the sum total of the UK’s response to this vitally needed technology.

Jeff Chapman: No. We have a further eight projects in addition to that one project that will bid for the extra three. The cost of bidding for these projects is enormous. If you have a one in three chance of getting funding for your project, that is enough to put an awful lot of investors off.

Q285 Chair: But what is the basis of your optimism that there will be eight bids for these three projects? We don’t know where the money is coming from for the three projects, when it will be available or precisely what the definition will be. The one project that we did have produced one bidder.

Jeff Chapman: It produced nine bidders.

Q286 Chair: They all bolted away. As soon as they had the details they said, "Oh, we can’t be bothered."

Jeff Chapman: No, that’s not quite true. Four were selected from the long list of nine and out of the four, there ensued what I called a process of attrition. That is true. But it is true that that are nine projects. That is the number of projects that applied for funding through the NER mechanism. The NER mechanism will be closely linked to the UK demonstration programme, obviously, because it will require funding from both directions. So the projects are out there. There is no shortage of enthusiasm. I have to say, and I’m going to crow now, the Carbon Capture and Storage Association is unique in the world. It is a UK organisation. There is no other organisation of this size and with its breadth of membership representing the CCS industry anywhere else in the world. The UK is ready to go. Industry is ready to go. We just need the right conditions and we’ll be there.

Chair: Let’s hope so. Thank you very much for your time. It has been a very useful session.

[1] Note from the witness: “ such as the ROC Banding Review, grid connection and planning