House of Commons Energy and

The Economics of

Oral and written evidence

Tuesday 10 July 2012

Ordered by The House of Commons to be printed 3 July, 10 July, 4 September, 16 October and 31 October 2012

Dr Robert Gross, Director, Centre for Energy Policy and Technology, Imperial College, Professor Sam Fankhauser, Grantham Research Institute on Climate Change and the Environment, Professor Gordon Hughes, Global Warming Policy Foundation, and Dr David Kennedy, Chief Executive, Committee on Climate Change; Robert Robinson, Secretary, Montgomeryshire Local Council Forum, Jeremy Elgin and Adrian Snook; Sarah Merrick, UK and Ireland Government Relations Manager, , William Heller, RenewableUK, and David Handley, Chief Economist, RES

HC 517, Session 2012-13 Published on 25 July 2014 by authority of the House of Commons London: The Stationery Office Limited £12.50

The Energy and Climate Change Committee

The Energy and Climate Change Committee is appointed by the House of Commons to examine the expenditure, administration, and policy of the Department of Energy and Climate Change and associated public bodies.

Current membership Mr Tim Yeo MP (Conservative, South Suffolk) (Chair) Dan Byles MP (Conservative, North Warwickshire) Ian Lavery MP (Labour, Wansbeck) Dr Phillip Lee MP (Conservative, Bracknell) Rt Hon Mr Peter Lilley MP (Conservative, Hitchin and Harpenden) Albert Owen MP (Labour, Ynys Môn) Christopher Pincher MP (Conservative, Tamworth) John Robertson MP (Labour, Glasgow North West) Sir Robert Smith MP (Liberal Democrat, West Aberdeenshire and Kincardine) Graham Stringer MP (Labour, Blackley and Broughton) Dr Alan Whitehead MP (Labour, Southampton Test)

Powers The Committee is one of the departmental select committees, the powers of which are set out in House of Commons Standing Orders, principally in SO No 152. These are available on the internet via www.parliament.uk.

Publication Committee reports are published on the Committee’s website at www.parliament.uk/ecc and by The Stationary Office by Order of the House. Evidence relating to reports is published on the Committee’s website at www.parliament.uk/ecc

Committee staff The current staff of the Committee are Farrah Bhatti (Clerk), Vinay Talwar (Second Clerk), Tom Leveridge (Committee Specialist), Marion Ferrat (Committee Specialist), Shane Pathmanathan (Senior Committee Assistant), Amy Vistuer (Committee Support Assistant) and Nick Davies (Media Officer).

Contacts All correspondence should be addressed to the Clerk of the Energy and Climate Change Committee, House of Commons, 14 Tothill Street, London SW1H 9NB. The telephone number for general enquiries is 020 7219 2569; the Committee’s email address is [email protected]

List of witnesses

Tuesday 10 July 2012 Page

Dr Robert Gross, Director, Centre for Energy Policy and Technology, Imperial College, Professor Sam Fankhauser, Grantham Research Institute on Climate Change and the Environment, Professor Gordon Hughes, Global Warming Policy Foundation, and Dr David Kennedy, Chief Executive, Committee on Climate Change Ev 1

Robert Robinson, Secretary, Montgomeryshire Local Council Forum, Jeremy Elgin, and Adrian Snook Ev 11

Sarah Merrick, UK and Ireland Government Relations Manager, Vestas, William Heller, RenewableUK, and David Handley, Chief Economist, RES Ev 17

List of written evidence

1 Adrian Snook Ev 23 2 Montgomeryshire Local Council Forum Ev 25 3 Professor Gordon Hughes, Global Warming Policy Foundation Ev 26; Ev 28; Ev 34 4 Grantham Research Institute on Climate Change and the Environment Ev 35; Ev36 5 Jeremy Elgin Ev 40 6 Centre for Energy Policy and Technology, Imperial College Ev 41; Ev 48 7 Renewable UK Ev 59 8 RES Ev 61 9 Vestas Wind Systems Ev 66

List of additional written evidence

Published on the Committee’s website at www.parliament.uk/ecc

Department of Energy and Climate Change (DECC) (WIND 01) Maureen Beaumont (WIND 02) D E Simmons CEng; MIMecheE; CMIOSH; RMaPS (WIND 03) Galloway Landscape and (GLARE) (WIND 04) Dr Ian Woollen (WIND 05) Energy Technologies Institute (ETI) (WIND 06) Viscount Monckton of Brenchley (WIND 07) ABB (WIND 08) Roland Heap (WIND 09) David Campbell, University of Leeds (WIND 10) Renewable Energy Foundation (WIND 11 and 11A) Brian Skittrall (WIND 12) Sir Donald Miller FR Eng (WIND 13) Hengistbury Residents’ Association (HENRA) (WIND 14) Environmentalists for Nuclear Energy UK (WIND 15) REG Windpower Ltd (WIND 16) Ian W Murdoch (WIND 19) Mrs Brenda Herrick (WIND 20) Mr N W Woolmington (WIND 21) Professor Jack Ponton FREng (WIND 22) Mrs Anne Rogers (WIND 23) Derek Partington (WIND 25 and 25A) Professor Michael Jefferson (WIND 26) Robert Beith CEng FIMechE FIMarE FEI and Michael Knowles CEng MIMechE (WIND 27) Barry Smith FCCA (WIND 28) The Wildlife Trusts (TWT) (WIND 29) Wyck Gerson Lohman (WIND 30) Brett A Kibble CEng (WIND 31) W P Rees BSc. CEng MIET (WIND 32) Chartered Institution of Water and Environmental Management (CIWEM) (WIND 33) Councillor Ann Cowan (WIND 34) Ian M Thompson (WIND 35) E.ON UK plc (WIND 36) Brian D Crosby (WIND 37) Peter Ashcroft (WIND 38) Campaign to Protect Rural England (CPRE) (WIND 39) Scottish Renewables (WIND 40) Greenpeace UK, WWF and Friends of Earth (WIND 41 and WIND 41A) Wales and Borders Alliance (WIND 42) National Opposition to Windfarms (WIND 43) Mr DJ Milborrow (WIND 44) SSE (WIND 45) Dr Howard Ferguson (WIND 46) George F Wood (WIND 48) Greenersky.co.uk and Sustainable Sitlington (WIND 49) No NOW group (WIND 50) Roger Helmer (WIND 51) Montgomeryshire Against Pylons (WIND 52) Element Power (WIND 53 and 53A) Brian Catt (WIND 55) National Grid (WIND 56) Abundance Generation (WIND 58) W R B Bowie (WIND 59) Kes Heffer (WIND 60) Alex Henney and Fred Udo (WIND 61) Mary Armstrong (WIND 62) Rainbow Trails Project (WIND 63) GE Energy (WIND 64) Wind Ltd (WIND 65) Communities Against Turbines Scotland (CATS) (WIND 66) EDF (WIND 68) Professor P Bullough (WIND 69) The Crown Estate (WIND 70) RWE (WIND 71) Theodor Oostindie (WIND 72) and Partnerships for Renewables (WIND 73) Judith Stretton (WIND 74) Anglesey Against Wind Turbines (WIND 75) Mark Blackwell (WIND 76) Banks Group (WIND 78) Energy UK (WIND 79) (WIND 80) Tata Steel (WIND 81) John Muir Trust (WIND 82) Engineering the Future (WIND 83) Mainstream Renewable Power (WIND 84) Bruce McIntosh (WIND 85) Richard Moore (WIND 87) Richard Phillips (WIND 88A and 88B)

Energy and Climate Change Committee: Evidence Ev 1

Oral evidence

Taken before the Energy and Climate Change Committee on Tuesday 10 July 2012

Members present: Mr Tim Yeo (Chair)

Dan Byles Laura Sandys Barry Gardiner Sir Robert Smith Ian Lavery Dr Alan Whitehead Albert Owen ______

Examination of Witnesses

Witnesses: Dr Robert Gross, Director, Centre for Energy Policy and Technology, Imperial College, Professor Sam Fankhauser, Grantham Research Institute on Climate Change and the Environment, Professor Gordon Hughes, Global Warming Policy Foundation, and Dr David Kennedy, Chief Executive, Committee on Climate Change, gave evidence.

Q1 Chair: Good morning and welcome to the investments in onshore wind, but both of them will be Committee. Can I ask the public to come in as quietly preferred over time to investment in CCGT as possible, please? We have a very big agenda to get generation. through before lunchtime and I do not want to waste Professor Fankhauser: Can I just reinforce two any time now. This is the first of three panels we are things that David said? The first thing to say is that seeing this morning, so we need to get through this the assumption with which you started is very bit of the session in about an hour, if witnesses and important—that we need low-carbon generation if we Members will please bear that in mind in their want to take our carbon budget seriously. questions and answers. Chair: That is not the purpose of this inquiry, though. I will begin by declaring my non-financial interest as Professor Fankhauser: But it is worth saying. the unpaid President of the Renewable Energy The second thing to reinforce is that we are also Association. I wish to make clear I have absolutely no worried about electricity bills, as many people are, financial interest in wind power of any kind. I have and onshore wind does have an advantage when it both supported and opposed applications for wind comes to keeping electricity bills low, but we do have turbines in my constituency, and I will continue to to acknowledge that there is occasionally an treat each one on the merits of the case. environmental trade-off. As you said in your opening I would like to ask a general question to begin with, remarks, that is a question of case by case, rather than and I want to ask it on an assumption, which I realise a sweeping generalisation on onshore wind. not all the witnesses necessarily share. If you believed Dr Gross: Certainly three of us are going to agree that Britain needs more low-carbon electricity, do you violently on this. There is evidence from around the think that onshore wind offers better value for money world, and we are in the middle of a big review of than some other low-carbon renewable technologies, the cost of generating electricity for the UK Energy including offshore wind? Research Centre. Both renewable and non-renewable Dr Kennedy: I can have a go at that. Certainly we at are included within that dataset, and it is very clear the Committee on Climate Change believe that we that in terms of generation costs—I think we are going should be decarbonising the UK economy, as set out to come on to infrastructure, intermittency and so on in the Climate Change Act. We think that means a as we go forward—they are not showstoppers, and need for early power sector decarbonisation, as we certainly in terms of generation costs onshore wind is have discussed here many times before. Within that, among the cheapest of the low-carbon options. onshore wind is an attractive option in the sense that Offshore wind is rather more expensive, but there are it is a cost-effective, low-carbon technology. The good reasons to hope that the costs can be brought kinds of numbers we work with for the cost of onshore down. wind are around about £90 per MWh at the moment, Professor Hughes: Can I perhaps play the role of falling to £80 per MWh over the next decade or two. dissentient? You asked the question to begin with You can compare that to offshore wind, for which at about low carbon and then added renewable. If you the moment we work with numbers of about £150 per look at low carbon, in my view nuclear power is MWh, falling to £100 per MWh over the next couple clearly the cheapest of all when you are looking at of decades, so there is a cost advantage in onshore the electricity system as a whole. When you add the wind. If you compare that to investing in unabated constraint of renewables, at the moment offshore wind gas-fired generation with a rising carbon price, the is more expensive than onshore, but my personal view cost of that generation starts to reach £100 and more is that that is going to reverse as we get more onshore per MWh over that same time frame. So, investment wind. The performance of onshore wind is going to in onshore wind is attractive, and investment in deteriorate because of lack of desirable sites, while offshore wind is necessary, given the limits to the costs of offshore wind are likely to come down Ev 2 Energy and Climate Change Committee: Evidence

10 July 2012 Dr Robert Gross, Professor Sam Fankhauser, Professor Gordon Hughes and Dr David Kennedy and there is a less of a problem with intermittency on you want wind power, you want to incentivise the it. So, I think we have to be careful about two things, investment, which would be a different mechanism. which is insisting it has to be renewable in a rather My personal view is that you ought to have a bidding narrow definition and, secondly, about the question of mechanism, not a mechanism that just has a standard the prospects today and the prospects in, say, 10 price. Negotiating site by site would be absurd. years’ time. Dr Kennedy: It is something to be considered in the context of the EMR. If you have some sites that need Q2 Chair: We shall know in a day or two whether 0.5 ROCs and some that need 0.9 to pay everybody— we will have the DECC view that support for onshore 0.9 is not ideal, but I think that is where we are with wind should remain at 0.9 of a ROC, or whether what the renewables obligations. There is an opportunity to is reported as the Treasury’s view—that it should differentiate within the EMR. come down to 0.75 of a ROC—will prevail. I think that we expect an announcement very soon. Which Q5 Chair: Professor Hughes, suppose we did have a one do you think is right? bidding system and that led to lots of successful bids Dr Gross: I think the danger is that it is being turned by onshore wind developers and no successful bids into a political decision when it is a techno-economic from nuclear generators. Would you be quite happy decision that should be made in a transparent way, about that? in a way that persuades the international investment Professor Hughes: I would regard that as being a community that Britain takes investment in low- better outcome than one that just simply gave an carbon seriously, including nuclear and carbon capture undifferentiated subsidy. Whether there are successful and storage—we are not just talking about renewables bids or not will depend on the terms of what is being here—and works out the level of support it needs in a offered, and that is the great problem in a bidding transparent way that avoids it being captured by system. By and large, bidding systems where they are vested interests, and then decides on the level of operated around the world have separate pools for support. The danger is that the contention that it separate kinds of technology. should be reduced because of political concerns is quite the wrong way to go about making— Q6 Chair: Leading on from that—this is to all of you—what proportion of UK electricity generation Q3 Chair: Putting that to one side, let us get a clear should come from wind power in, say, 2020? answer. Do you think it should be 0.75 or 0.9? Dr Kennedy: To repeat the scenarios that we have Dr Gross: The evidence suggests to me that 0.9 is talked about before, I think over the next decade, in a perfectly reasonable figure at the moment, because terms of onshore and offshore wind, they could developers in this country have to manage uncertainty account for about 20% of total generation. That is around electricity wholesale prices. If—as we intend consistent with the Government’s approach to meeting to over time, and as we see in other countries—we the renewable energy targets in Europe, but it is also had a fixed FiT, I would suggest that the level of a sensible thing to aim for in the context of meeting support could be slightly lower. carbon budgets. We have set out an indicative scenario Professor Hughes: That presumes that the ROC is a for 2030. It is not a blueprint—I am always very good system of supporting renewables—I think it is a careful to say that—but in that indicative scenario dreadful system. The answer to that question is, first, what is sensible to aim for in broad terms at the shouldn’t we have a better way of dealing with it? moment, we think, may be 40% renewables. Most of However, if you are going to stick with renewables, that would be wind generation in 2030, with 40% wind farms in general are extremely profitable at 0.9 nuclear, 15% CCS and a little bit of unabated gas- of a ROC. They could perfectly well be brought down fired generation on the system for balancing purposes. to a lower level than that. Whether it is 0.8, 0.75 or Dr Gross: It is perfectly reasonable to be looking to 0.7 is something that is going to vary a great deal wind in the period to 2020 to be providing somewhere from site to site, rather than as a general rule. in the region of a fifth to a quarter of UK electricity Professor Fankhauser: Yes, I think the main thing is requirements. That would be equivalent to something what you just said at the end: different wind sites have like—without wanting to be over-specific—10 to 15 completely different profitabilities, so it is, again, very GW offshore and 10 GW or so onshore. Numerous hard to generalise. At 0.9, I am sure there are wind studies—system modelling studies and engineering- farms that are overly profitable, if you will, but we based studies—that look at the way the system is have to see what is the total amount of onshore wind utilised and operated suggest that kind of proportion that we want to encourage, and we have to look at could be accommodated with a minimum amount of those sites that are perhaps not the most profitable that energy being wasted through curtailment, for we want to put through the pipeline as well. example. It would lead to almost a one-for-one reduction in carbon emissions, although there will be Q4 Chair: Are you both advocating a site-by-site some impact because of having greater amounts of negotiation for the level of support, which depends on variation on the system, and it is completely consistent the profitability of the site? That seems to be a with the kind of build rates that we have seen achieved passport to endless lobbying. in our near neighbours. Professor Hughes: That was why I said that ROCs is I might add, if we could build as much wind by the a terribly bad system because it is a mechanism that mid 2020s as the Chinese appear to be able to build rewards energy rather than providing electricity in a single year, we would meet our targets quite capacity, given that there are zero operating costs. If comfortably. Energy and Climate Change Committee: Evidence Ev 3

10 July 2012 Dr Robert Gross, Professor Sam Fankhauser, Professor Gordon Hughes and Dr David Kennedy

Professor Fankhauser: It is no surprise that I fully that you would be better off investing in unabated gas agree with the CCC targets. I am signed up on those. than wind and, from an emissions perspective, that I would just reinforce what Rob said. Those numbers would give you a bigger bang for the buck. If you are not outlandish, if you compare them to what is think out to 2050 and our power system where we happening in Denmark, for example, which already expect to have demand of 500 TWh, if you have a has 20% wind and 30% renewables, or Germany, carbon intensity of gas-fired generation that gets as which has 15% renewables in electricity. We are not low as 350 g, you multiple those together and the going out on a limb by doing that. emissions from a gas-fired power system would be Professor Hughes: The real question is what the much more than the 160 million tonnes allowed for country is willing to pay for. We could probably have the whole economy under the 2050 target. So, 30% or 40% wind if people are willing to pay a very unabated gas is not the way to go. It is incompatible high price. When people do serious economic studies with our carbon budgets. Investment in renewables of real markets, the efficient level of wind, and intermittent generation, alongside other low- unsubsidised, is below 5%. That is detailed studies of carbon technologies. I agree with Gordon that it is not north-western Europe that I am familiar with, and all about wind—it is about wind, nuclear and CCS— other ones. The simple answer is: what are you but that is what we need to do to meet our carbon prepared to pay for? The question will be that that is budgets in the legislation. a cost that is going to be borne by the public at large. Dr Gross: Can I just address the very specific question In other words, if you do not make the public pay, it that you asked, and I will address it in the short will be down below 5%. term—so, looking to 2020? I can’t think of an Professor Fankhauser: Could I add a little quibble to appropriate word to describe the notion that the that? What do you mean by “unsubsidised”? We have carbon emissions that are taken back through the part to factor in a cost of carbon in all that, so the level of loading of the fossil fuel plant exceed the carbon subsidy would have to be relative to fossil fuels emissions that are saved. Balderdash; it just is not paying the full cost of carbon. Then it might change correct. The only way that could possibly occur would what you just said. be if you did some utterly bizarre things in the power Professor Hughes: The studies I am referring to system that a market-based system or any kind of already have a carbon price that exceeds the sensible, economically operated electricity system maximum that the Government envisages for 2020. anywhere in the world simply would not do. We do know that if you part load an old 1990s CCGT Q7 Chair: It has been suggested that a system that gas-fired power station, its efficiency will be reduced relies heavily on wind power may produce emissions as a result, but what would happen is that the as high as one that runs only on efficient gas, because efficiency might go down from being say about 50% part-loaded fossil fuel power stations are required to the low 40s, but you will not be part loading all the when the wind is not blowing strongly enough and CCGT on the system. A whole range of things will they will release more emissions than efficient gas happen on the system as the wind comes in. The turbines running on their own. What is your view system already has to cope with very large swings in about that argument? demand on a daily basis. The first plants that you Dr Kennedy: I can come back on that. I think you switch off are the oldest, least efficient, most are quoting an argument from Gordon’s paper, among polluting, highest carbon plants. That is the way the others. What I strongly agree with in Gordon’s paper market works to optimise the utilisation of plant in is that what you need to do here is very detailed the power system, so there will be a modest penalty system modelling to understand what the impact is in associated with accommodating wind on the existing terms of emissions, and that is what we have been system, but that penalty is extremely small in doing over the last several years. Just to give you a comparison with the emissions reductions that are sense of what that modelling says—again it comes out available from wind, effectively, by reducing the burn of our detailed modelling—in 2020, with a 20% share of fossil fuel and by turning down fossil fuel plants. of wind generation, we would go from a carbon As we look out, say to 2030, we can see a number of intensity on our power system of 500 g of CO2 per things that can help to reduce that take back, if you kWh at the moment. That goes down to about 300 like, still further. through switching from coal to gas generation, and One of the most exciting things that is happening in then it goes down from 300 to 200, so that is a very the power sector market at the moment is that the clear saving because of our investment in renewables manufacturers of combined cycle gas turbines are over the next decade. If you go beyond that, again focusing very hard on maintaining their efficiency our detailed modelling says that with a 40% share of through a wider range of operating conditions. We are renewables, you need only about 5% unabated gas- getting quite close to the theoretical maximum that we fired generation to back that up. In 2030, we think that can achieve in terms of efficiency with CCGT at peak combination of 40% renewables, other low-carbon operation. Those 1990s CCGTs were designed to base technologies and a bit of gas will get us that 50 g of load. They were not designed for the kind of deep CO2 per kWh carbon intensity, which is a very cycling that we might need—not by 2020 but perhaps familiar number. by 2030—and through improvements in that If you go further out in time, you can get higher levels technology we should see this penalty reduced. It can of renewables—60%, 70% or 80—with only very be reduced further if we have increased limited gas-fired generation to balance the system. So, interconnection, demand response and storage. The to finish off that argument, I think there is a suggestion Committee, I know, is already familiar with many of Ev 4 Energy and Climate Change Committee: Evidence

10 July 2012 Dr Robert Gross, Professor Sam Fankhauser, Professor Gordon Hughes and Dr David Kennedy those things. I am very happy to provide some Q8 Barry Gardiner: I am interested in seeing what supplementary detailed technical input on the question effect an increase in wind generation may have on of managing intermittency. investment in gas. There is a chance, is there not, that One further point I would like to make, because I it will make investment in gas less attractive, because know this has also been touched on, is the notion that gas will face future lower load factors which will we end up curtailing vast amounts of our low-carbon increase the uncertainty of the revenues that one can power as soon as we get anywhere near our targets. expect from gas-fired power stations? What do you That really is not correct either; again, I can provide think the impact is going to be of having greater wind a detailed supplementary on that point. on the investment appetite for building gas? Professor Hughes: We disagree. I have as much Professor Hughes: In my view, we have just experience of modelling power systems as Dr Gross described the current system. You invest on the basis has. We are simply making different assumptions of the expected revenues that you are going to get out about what is going on. Everything that he has of generating and selling electricity into the market. referred to is on the basis that what we are doing is Two things are going to happen, and nobody disagrees essentially using old CCGTs within a circumstance of about this: first, the difference between the peak and the low troughs of prices is going to get more extreme a system to back up the intermittency on the wind than in the past, so it is going to become more power side. What you really have to do is look important as to when you expect to be able to sell forward. What one is looking forward to is the your power. The second thing is that certain kinds of replacement of quite a lot of retiring capacity— power are going to get dispatched less and therefore nuclear power and other elements of our system that generate less revenue. The normal response to that are going to go offline over the next 10 to 15 years. around the world has been to abandon the idea that When you do that, you have a choice between you only compensate people for selling electricity, and investing in gas CCGTs, which are very efficient, as that you create what is known as a capacity market of has been explained, or alternatively you put in an some form or other and you reward people in that awful lot of wind power and you do not, by and large, way. If you do that, you can get investment in pretty put in CCGTs—you put open cycle plants in instead. much what you want, provided that you run the The consequence is that open cycle turbines are much auctions or the compensation correctly. If, on the other less efficient, and it is that mechanism that is the route hand, we stick to paying people only on the basis of by which you can finish up with the result that I have energy, you are going to push up the cost of capital described, which I stand by. for everybody, because essentially what happens is Essentially, this is not something that is a matter that the risks that you are going to be expected to bear where we are differing on the technologies. What we are going to be greater, and therefore they will want are differing on is the way the system operates and to have a higher return before they put out their the changes that you are looking forward into the investment and they will seek to recover their returns future about. over a shorter period of time, which either translates The other thing I should say is that it really does into higher prices or less investment. depend on the nature of the system. We are talking Dr Kennedy: I think we can agree on this one. Clearly, about hugely detailed elements of systems. If we had a if you do not know what the load factor of your gas- lot of hydro power in Britain, it would be a completely fired plant will be, you would be pretty worried about different story, but we don’t. That is the great sadness putting money in and whether you would get a return from the point of view of wind power in the UK, on your investment. That is well acknowledged by, I which is that wind is a wonderful complement to think, pretty much everybody here. We need a hydro power, but a very bad complement to a variety capacity mechanism in the context of moving to a of other sources that we have. low-carbon system. There is a capacity mechanism within electricity market reform. Whether that is the Dr Gross: Can I come back very briefly? With right mechanism, we can debate and discuss—it is not respect, we can all hypothesise, arm wave and make for today—but certainly we need to feel confident that up scenarios on the back of an envelope where we do the gas-fired generation will come forward. I think irrational things with the energy system, and the result there is a corollary of that: do we really want the gas- is that costs go up or carbon emissions go up or fired generation investment coming forward if it is just something like that. I am not referring to hypothetical going to sit there and not generate apart from, for instances where we do things that are just, frankly, example, when there is a lull in the wind—the 5% plainly daft. I am not referring to my own modelling; load factor on average that I have talked about? The I am referring to colleagues in electrical engineering answer is, yes, you do. The cost of having it sitting at Imperial College, and I am referring to a vast there doing nothing is not very much. Bear in mind international literature that has looked at this. It is not that of the total cost of a gas-fired generation plant, the case that nobody has thought of these things only about 15% is the capital cost, so 85% is the anywhere else in the world, or thought of them before operating costs, which you don’t incur if it is just in this country, and what I am talking about is what sitting there not running. would happen to the system on any kind of rational, Dr Gross: I think we have found something that we cost-effective basis for replacing old plant, which has broadly agree about. As you bring more zero fuel cost to happen, and managing wind, managing nuclear— generation into a system, you tend to depress the which also brings challenges because it is rather average wholesale price and you tend to make prices inflexible—and managing demand swings. more volatile. That can make investment in new gas Energy and Climate Change Committee: Evidence Ev 5

10 July 2012 Dr Robert Gross, Professor Sam Fankhauser, Professor Gordon Hughes and Dr David Kennedy generation more risky and therefore less attractive. I renewables and everything to do with the think the real challenge is to make sure that we reward international— flexibility in all its forms and minimise the cost of achieving that flexibility, and that might be through Q10 Barry Gardiner: You sound like a bunch of more flexible gas plant. It will also be through the politicians. The pushback I am getting is—I think you other things that we have touched on already, in are all agreeing with me, aren’t you?—that prices are particular increasing interconnection and demand actually going to go up? response. Dr Kennedy: There is a clear cost—let’s not pretend that there isn’t—which is £100, and let’s not say that Q9 Barry Gardiner: Even among you guys who the £100 doesn’t matter because of energy have disagreed so violently—or three to one have efficiencies. It is £100—accept it, debate it and disagreed so violently so far—there is unanimity that discuss it. As Gordon says, “Are you prepared to pay electricity prices are going to rise as a result of our it as a society?” That is the question, and it is a push on renewables and about the increase that that political question. will have in a knock-on effect on gas prices as well, Professor Hughes: I don’t think you expect us to or electricity from gas. agree on what the cost is, but we agree that it is going Professor Fankhauser: I think the thing we agreed to go up. on is that we need a capacity payment, and then you can then ask what the overall cost is of making the Q11 Barry Gardiner: Professor Hughes, you will system flexible enough to deal with the extra wind have seen that there is some research that suggests capacity. The numbers that the Committee on Climate that because there may be a merit order effect, as has Change has produced suggest that this is a relatively been evinced in Germany and in Denmark, it may low cost. If I remember rightly, it is about 1p per kWh. lower the price of electricity because it has displaced That covers everything that you need on the power from generation with higher marginal cost. Do transmission system, on interconnection and on back- you accept that is also a factor that we need to put up capacity. The whole strategy of dealing with this into this mix? new power sector is about 1p per kilowatt hour, which Professor Hughes: Yes, that is indeed possible, but it is extra money but not too much. is only looking at a small— Dr Gross: I think it depends entirely on what you assume might happen in looking over the next 10 Q12 Barry Gardiner: Sorry, is it possible, or has it years to gas prices. We are all agreeing that there is a happened in Denmark and Germany? I thought the need for more flexibility and we are all agreeing that research showed that it actually took place. investment in gas may become more risky. I don’t Professor Hughes: Yes, I would entirely accept that, think that that therefore means that we were all but that is because the subsidies that are required there agreeing that the impact on consumers is hugely to bring that extra capacity are taken out of the calculation. In other words, the marginal cost has gone deleterious, or in fact that the cost of gas was going down, but the fixed cost has gone up. That is all part to go up as well—quite the reverse. Having a lot of of the story that the Committee on Climate Change renewables can depress the average wholesale price of has as well. electricity, which is a beneficial thing for consumers. Barry Gardiner: I was just going to come on to that. Q13 Barry Gardiner: In those same calculations Dr Gross: A sense of perspective is very important. that you would wish to do, are the subsidies for fossil The kind of impact of moving to decarbonise the fuels taken into account? electricity system, if we do it carefully and Professor Hughes: Are you saying are they taken intelligently and over a period of time, with the right into account? regulatory structure in place, is very modest in Barry Gardiner: You were offering me a scenario. comparison with the kind of dramatic swings that we You said that in those studies that is the case, but it is have seen in electricity and gas prices as a result of the case because they haven’t taken into account the international commodity price movements, in subsidies that are being given to the renewable sector. particular for the price of gas. So, I said that if you factor that in, does your Dr Kennedy: I think we have said the headline figure argument—that that might not be quite as beneficial before. If we do all the things that we have suggested and lower for prices—hold good if you then factor in we need to do over the next decade, it would increase the subsidies that have been given to the fossil fuel the electricity bills in 2020 for the typical dual-fuel sector? I am asking you if it is a fairly straightforward household by £100 relative to today’s level. Within balancing act. that, about £70 is due to the support for renewables, Professor Hughes: The simple answer is that my and within that about £50 is due to supporting wind argument would not be changed by those. In other in particular, rather than biomass—and most of that words, the overall cost has gone up. What you started £50 is offshore rather than onshore wind. Those are with was the statement that, at the margin, the costs the facts, and we always say quickly after that there of generating a certain amount of electricity have gone is an energy efficiency opportunity of about £100 that down because we switched from burning coal to we should try very hard to get, and if we can, bills having wind, which has a very low marginal cost. I will stay at the current level. accept that. But what I then said is that there is a Dr Gross: Bills roughly doubled in the period from subsidy to wind plants that is being recovered outside 2005 to 2009, and that had nothing to do with the system, and that means— Ev 6 Energy and Climate Change Committee: Evidence

10 July 2012 Dr Robert Gross, Professor Sam Fankhauser, Professor Gordon Hughes and Dr David Kennedy

Q14 Barry Gardiner: Then I asked you whether you Dr Kennedy: Yes, it gives you price stability. Just to had factored in the other side of the equation—the give you a sense of what you pay for under the subsidies that are given to fossil fuels. contracts and what you pay for not under the Professor Hughes: Yes. contracts—so you are still exposed to gas price Barry Gardiner: You have? volatility—95% of the market would be under Professor Hughes: Yes. contracts for difference in 2030 with a predictable price and 5% would be subject to volatility because Q15 Laura Sandys: Can I just come in on that? I that is around unabated gas-fired generation1.You don’t know whether the panel believe that when we move away from the current situation where the price start to look at 2030, or 2020 to 2030, we should start is almost fully determined by the gas price. considering decoupling the energy prices that are Professor Hughes: This is really what a lot of this is domestically generated and those on the international about: do you want a market system for electricity or market. Do you feel that international wholesale do you want the CGB? Basically, the system that prices are distorting—and will distort into the future— David is describing is the CGB. We just go back to a the cost of renewable energy generation? Government-managed market, in which case the price Professor Fankhauser: At the moment there is some, that is charged is essentially the average price to but not very much, interconnection with the UK customers. electricity system and other electricity systems, which means that there is not much of a link between our Q17 Laura Sandys: But if you are consuming electricity prices and other electricity markets. It is energy that is not gas primarily, why should it be indirectly through the fuel price. If we have a future linked to a gas price? where you would interconnect more, you would Professor Hughes: If you have a market price— expect prices to be more similar. That is the whole Laura Sandys: But why would that be a gas market idea of trading. rather than a different market? Professor Hughes: We have a system where the Professor Hughes: Because with a market price, that market price is, for a large part of the year, driven by is set by the marginal cost of the last, most expensive the gas price, so the argument we are dealing with is generator that has to come on stream. Essentially, if can we decouple that. My answer would be that pretty you were running gas at all, that is the most expensive much you can’t, because you are going to finish up marginal cost and sets the market price. That is the with the gas price—at least for a considerable period way the market price has gone over the last 20 years. of time—being the back-up that drives the marginal The situation that has been described here is one in price for a lot of the time. You are going to be which we abandon that basic market structure. We operating in two regimes. One regime is where we move to a structure in which everything is driven by have lots of wind because the wind is blowing and complicated agreements that come down to an you don’t need very much gas generation to be on averaging mechanism over a period of time. stream to determine the market price, so the market Dr Kennedy: That is what we are doing in the price is going to be lower during that period. Then electricity market reform anyway. you will have other periods where you need gas Dr Gross: I think it is important just to avoid a certain generators to operate, and then they have to recover amount of overstatement and conflation around all of their marginal costs, in which case it is the gas price. this. What the electricity market reform agenda My view of the market is that that is going to be the aspires to do—it is another matter, in which this majority of the time. Committee is also deeply involved, as to whether it Dr Kennedy: Under the electricity market reforms, if will manage to do it or not—is to provide long-run, we are successful—if we decarbonise the system and fixed-price contracts for what I describe as asset based generation, so that is nuclear and the renewables. if we get back to that 50 g of CO2 per kWh emissions in 2030—most of it will be paid for under the They are not subject to the kind of price excursions contracts for difference. There will be a little bit to that you would see with a CCGT because 70% or 80% pay for, which is the balancing generation, and that of the electricity price that CCGT effectively produces will not be the dominant thing within consumer bills. is a product of the input fuel price that is required to So we will decouple from the gas price. There is a burn. It is perfectly reasonable, I think, to envisage a question: is there a benefit in decoupling from the gas future—as is the case at the moment in France, for price over and above the carbon benefit of example—where your domestic electricity prices are decarbonising? That depends on what you think the less subject to the vagaries of the international price risks are of being in a high fossil fuel price world. If of gas than we have seen in recent years in the UK. It you think that is a very significant risk, there is an may well be that as we look out into the future, we additional benefit to being decoupled from the gas are into this golden age of gas and the price of gas price. falls. I think that remains to be seen. I don’t know; it is extremely uncertain. But, it is also the case that Q16 Laura Sandys: Certainly when you look at fossil fuel prices have historically been extremely consumers—whether they are consumers or 1 Witness Correction: ‘95% of the market would be under businesses—volatility is one of the biggest problems. contracts for difference in 2030 with a predictable price and It is one of the biggest difficulties for business 5% would be subject to volatility because that is around unabated gas-fired generation’, should read ‘the large functioning. If one is talking about the opportunity of majority of the market would be under contracts for decoupling from a volatile international marketplace, difference in 2030 with a predicable price and around 5% does that not deliver energy security on price? would be for unabated gas-fired generation’. Energy and Climate Change Committee: Evidence Ev 7

10 July 2012 Dr Robert Gross, Professor Sam Fankhauser, Professor Gordon Hughes and Dr David Kennedy volatile, and it is likely to be the case that the price of cost reduction in all of those, and that is where the gas continues to be volatile. Although the points that £100—a 35% cost reduction over the next decade or Gordon makes about price setting, the marginal plant two—comes from. Can you ever get it below that? and everything are completely valid, if a smaller Possibly, but it then becomes more uncertain, and you fraction of your overall electricity sales are going have to get it below that to say that it is cheaper than through the system—Already, the electricity onshore wind. companies smooth out a whole bunch of volatility due Professor Hughes: I think you asked the overall to time of day and time of year, and the consumer question. To be fair to offshore wind, it has a higher doesn’t see those, whether they are a small business expected load factor and it will operate for more or a household. If you move to a system that has more years. Potentially, if we diversify around the UK, it renewables and more nuclear, you move to a system should be less intermittent collectively than onshore that has more stable prices for its consumers. That is wind. From that point of view, there are a variety of absolutely unequivocal. ways in which having it at a fairly large scale can Chair: Let’s move on a bit. potentially bring down the costs. With actually building wind farms, they are incremental. The major Q18 Albert Owen: Can I just come back to the issue economy of scale is simply a transmission capacity that the Chair first asked about: comparing onshore from bringing onshore on the transmission, but the and offshore wind generation? You mentioned in turbines are not big by the standards of electricity particular that both are going to come down generating units and you just have an awful lot of substantially over the next few years, but have you them that you have to put down in one way or another. taken into account the intermittency in transmission It is a small economy of scale maybe, but not a huge that is associated with that? Is that part of the cost that one per se in the overall scale of things. What really you have just given, Dr Kennedy, when you gave your counts is the system as a whole. figures of down to £80 for onshore and down to £110 for offshore? Q21 Albert Owen: Comparing onshore and Dr Kennedy: Sam gave you the estimate of the offshore? intermittency cost, which is up to about 1p per kWh. Professor Hughes: Yes, that is right. It doesn’t ever get more than that. For low levels of Dr Gross: Can I just come back to your original intermittency it is less, but as you get to very high levels of intermittency—I am talking about 70% or question of what transparent and what is included and 80% on the system—we think that the intermittency what is not included? The offshore wind developers cost is 1p per kWh. That is a small proportion— are obliged to bear the cost of the connection to the 10%—if you take offshore wind in the longer term shore. That is paid for through their subsidy under the at 10p per kWh. It does not change the fundamental RO, and that is a distinction between the requirements economics of whether it is sensible to develop for wider transmission system upgrading, which is not offshore wind. It is, even when you account for the paid for through the renewal subsidy and does not intermittency costs. show up in those cost numbers, and the specific connections to the offshore farms that does show up Q19 Albert Owen: What about economies of scale in those cost numbers. The cost of the wider here? We flew over one of the largest wind farms. You transmission system upgrading has been looked at in are not going to get that on land anywhere, are you— considerable detail by something called the Electricity that kind of volume of more predictable wind—so is Network Strategy Group, which involves Ofgem, this really factored in correctly? We are talking about DECC, the national grid, some of the big companies planning applications that are coming in in my area of and some independent experts, and it sounds like a north-west Wales, which is relatively windy on land very large number. I think the current estimate is and offshore, but the scale of the offshore generation something of the order of £8.5 billion to do all of is so much that certainly the technology will improve this upgrading—not just to connect wind farms but in the future so that you can have direct currents. The the upgrading that we need. But when you annualise technology and the Government policy are moving in that over the lifetime of that asset and then divide it a way that will make offshore wind far more into the overall electricity sales in the country, it ends economic in the long term than onshore. Why should up being a rather small number—I think it is we be bothering with onshore when the margins that something in the order of between £5 and £6 per you have just given exist? household per year. Dr Kennedy: I agree that we can get offshore wind I do think there is a need to be more transparent about costs down very significantly; I have said from £150- some of these costs. The costs of the renewables plus at the moment to— obligation are reported very transparently and the costs of the offshore connection are borne by the Q20 Albert Owen: It is the sheer volume as well. I offshore developers, but some of the wider issues don’t think we are dealing with the sheer volume of around managing intermittency and some of the what we can get from offshore wind. Is it predictable? transmission costs could be reported more clearly and Dr Kennedy: When we look at how do you get down transparently. There is a need for more work, because from £150-plus to £100 and possibly lower, we ask it is complicated—making the complicated simple is all those questions. What can you do in terms of difficult—and that might cut through some of the scaling up? We break apart a , we look at disagreements that you might see between some of the the construction process and we look for the scope for members of the panel this morning. Ev 8 Energy and Climate Change Committee: Evidence

10 July 2012 Dr Robert Gross, Professor Sam Fankhauser, Professor Gordon Hughes and Dr David Kennedy

Albert Owen: It is good to get disagreement at times I would just qualify that. If you talk about micro, I for us to formulate a balanced report. think there are costs and technical issues around very Professor Fankhauser: I would just re-emphasise small wind, which suggests to me that although it where the numbers that David has given come from. absolutely has a role in some locations—I am talking There are elements where offshore wind is better than here about much smaller wind turbines, which have onshore, and there are issues where onshore has an a niche and are very important, and there are some advantage. The maintenance of offshore will probably absolutely terrific UK products available—I don’t always be more expensive just because of the location think we should expect it to be able to displace and the difficulties of that. The construction of significant amounts of larger, industrial-sized wind offshore will almost always probably be more turbines. That is just not technically feasible. In terms expensive than onshore. But then offshore has of solar, we are seeing the costs coming down and the advantages, as we have heard, in terms of the load available resource, even in the south of England, is factor. Probably the intermittency is less, but that potentially quite significant as we look further ahead depends on sites, and the environmental impacts of into the future if we can get the costs of that down. I offshore are slightly less as well. So there are certain think there are things that need to be done to facilitate elements where offshore has an advantage and there this kind of community involvement in small wind are elements where onshore has an advantage. The aggregate picture is the one that David has given you. farms, not necessarily micro-wind. Professor Hughes: I come from a part of Scotland Q22 Albert Owen: One thing that has been lost in that is probably similar to your part of Wales. I am this debate and argument very recently is also chairman of our local community council, which microgeneration and community benefits. We are is the equivalent of the parish council, and I can tell talking about building the biggest, the most and the you that even individual wind turbines on people’s cheapest, and we have lost the arguments about how farms are intensely controversial in that kind of area, the community and individual households can benefit. let alone big ones. Two things we have learned: we in Would you like to comment on that? Scotland have an organised community benefit Professor Fankhauser: Yes, for me it depends a little arrangement where roughly £5,000 per MW is bit on technology. Obviously things like nuclear and contributed. You will find that most of those funds are offshore are inherently suitable for the occurrence of not regarded with great favour by the local the big utility model. inhabitants. Secondly, opportunities for ownership of small-scale turbines and so forth are extremely Q23 Albert Owen: I am not suggesting every constrained by the situation with landownership and a household has a nuclear power station. variety of other things. I would be very sceptical that Professor Fankhauser: You’ve just been pushing for there is, as it were, the opportunity to do the sort of offshore. You can imagine onshore systems that are things that have been done in Denmark in my area of community based. If we are honest, the UK is not Scotland and probably your part of Wales as well. quite as good at getting those off the ground as, for example, Germany or Denmark, where you have Q25 Chair: Professor Hughes, you said that the municipally—owned small power systems. Somehow problem of intermittency might be less for offshore that is not the culture; that is not the economic system wind than onshore wind. Why is that? that we have. Probably that is one of the reasons why Professor Hughes: Yes, because of the overall area of our planning process takes longer and has a lower wind that can be captured. Imagine doing them off the success rate than that in, say, Germany or Denmark. north-east coast of Scotland and the south-west coast of Cornwall; that is a fairly large area and the wind is Q24 Albert Owen: I don’t think many people who less affected by onshore topography in various ways. object to onshore wind farms would object to micro if What you can get is steadier and longer periods of it was done on a small scale and there was community time in which collectively all of the offshore wind benefit in the way that solar panel has been rolled out, farms may be able to generate. I have looked at the in many ways. figures in detail for the last year. You will find that Dr Gross: I think it depends on what you mean by at the lowest period, literally no onshore micro. If you are talking about full-size wind anywhere in the UK is operating. On the other hand, turbines—say 1.5 to 2 MW turbines; big wind there is the possibility, at least, that if it is well placed turbines—owned by communities, that model has and diversified, offshore might get 5%, 10%, or even been very successful in facilitating the roll-out of 20% operating at any time. wind in our near neighbours. For various reasons, we did not hit on a policy mix in this country back in the mid-1990s that was conducive to that. They did—I Q26 Chair: Just leaving aside the possibility of think largely by accident. So we have this kind of planning objections, are you saying that there are no legacy where we have never created the conditions for sites available onshore that could achieve the same communities to get involved in investment in wind outcome as offshore? farms. We haven’t created a supportive constituency Professor Hughes: It is an inherently smaller area, so in the way that some of our near neighbours have. We the diversity and the wind conditions are inherently are not the only country in the world with stringent going to be less than when you start to consider the planning laws by any means; I think that is very whole of Britain’s waters around the important. as a whole. Energy and Climate Change Committee: Evidence Ev 9

10 July 2012 Dr Robert Gross, Professor Sam Fankhauser, Professor Gordon Hughes and Dr David Kennedy

Q27 Sir Robert Smith: I had better remind the I do think we need to move away from the notion that Committee and the witnesses of my entry in the we are just going to do this as business as usual, where Register of Members’ Interests, particularly to do with a big company comes in with a big landowner and the oil and gas industry and a shareholding in Shell. effectively gives a bone to local town hall in the hope When it comes to offshore construction costs, are we that it will shut everybody up and stop them being confident about the experience of bringing these unhappy. I think we need to have a thoroughgoing things down when a lot of the offshore to date has look at each of the different components of policy in been near shore rather than seriously offshore, and we this country, starting with the nature of the instrument are going to be looking at steel jackets and a lot more and starting with the feed-in tariff, and going through infrastructure in the construction phase? Can we be to looking at the Green Investment Bank and other that optimistic about the costs coming down? provisions, including the tax system, and seeing the Professor Hughes: When people talk about the costs opportunities for greater community ownership of coming down, they talk about them coming down wind. I don’t think we are doing that because that is relative to a series of increasingly high baselines as going to provide us with dozens of gigawatts of wind you move further and further offshore. So, yes, it is in a huge hurry, but I do think it needs to be looked significantly more expensive if you are going to go 50 at in order to make this something that people feel miles out than if you are going to be only 10 miles more part of and therefore less oppositional towards. out because, in part, the conditions that the turbines Professor Hughes: In the end this is about what goes have to withstand are potentially going to be a great on on the ground. I look at it from the perspective of deal more potentially threatening and the waters are a fairly local view. When it comes down to it, what is deeper. What one is talking about is prices that come involved here is who benefits. There is a certain value down over time for a given site. of having wind under a guaranteed tariff and all the other things in a particular location, depending on Q28 Sir Robert Smith: We have already touched whether it is windy, such as being well located to the quite a bit on the community benefit as an attempt transmission network and so forth. That is going to be to balance the community impact. Do you think the divided between the community and the landowner, Government’s idea for England of business rates being and so the more we give to the community, the less kept by the local council will help to make people feel will be available to the landowner, who will therefore that the wind farm is having at least a positive local be much less likely to co-operate in locating them. On benefit at the same time as having an impact on their the other hand, if we give it all to the landowner, the environment? community resists a great deal. That is a balance that Professor Hughes: It might change the attitude of the is extremely hard to strike, and it is very hard to strike councils. It will not change the attitude, I suspect, of in the most remote, least populated and typically much of the population. concentrated ownership parts of the country, like my part of Scotland. Wales is a bit different in this Q29 Sir Robert Smith: Can anything more be done respect. In essence, the conflict that you can see in to share the benefits locally? southern Scotland or in northern Scotland is that the Professor Fankhauser: There are various things in people who live there do so because they want places addition to sharing the benefit. It is also a process one that are wild, untouched and typically remote, and has to go through and people have looked at the they do not like having wind farms around them process in places like Germany and Denmark. They because that spoils the inherent virtue of the landscape have found that early on there is quite proactive from their point of view. That is a very difficult involvement of the community in addition to the conflict to resolve. benefit sharing. It was also that some of the projects did originate from the local community, rather than Q30 Sir Robert Smith: Nevertheless, in view of being imposed on it, and then sharing the benefit. As your enthusiasm for a market approach in respect of Rob said, I think there is a whole different other areas of energy policy, is there anything wrong institutional / regulatory psychology in some of the in principle with saying to someone, “Okay, you have other countries that we might have to look at. this natural advantage of living in this beautiful Dr Gross: If you look at what happened in Denmark remote place. We want to take away part of that and Germany, for example, there were a number of advantage and we are prepared to compensate you factors that facilitated things. In Germany, they financially”? There is nothing wrong with that in created these closed mutuals where the local people principle, is there? who had a few quid to spare could invest in the wind Professor Hughes: No, nothing at all. I am entirely, farm—say a 20 MW wind farm—and they would get in principle, in favour of that. If we have a planning a return from that. First of all they had a fixed feed- system that incorporates true compensation for the in tariff, so the returns were very secure provided the people who are affected, it would seem to me to go a turbines didn’t fall over and they put them somewhere long way, but we don’t. We have a planning system reasonably windy. They also had opportunities to that has essentially encouraged people to take benefit from advantageous loan conditions from polarised positions rather than negotiate to reach, as it various state, quasi-state or municipal lending were, the deal that makes sense for everybody. institutions. They were able to roll this out and benefit from this at a much earlier stage than we are at now. Q31 Sir Robert Smith: Is there a bigger debate I think Gordon is absolutely right in questioning the where that environment you are looking at is also extent to which we can replicate all those things, but going to be impacted by climate change, whether you Ev 10 Energy and Climate Change Committee: Evidence

10 July 2012 Dr Robert Gross, Professor Sam Fankhauser, Professor Gordon Hughes and Dr David Kennedy are living in the remote area or in an urban area? If some money away from consumers and spending it you are going to have to tackle climate change, you on the construction of wind farms. The kind of output may have to play your part. analysis, or the general equilibrium modelling that Professor Hughes: This is the small versus the large. looks at the economy and how it adjusts to those kinds It is not going to make the slightest bit of difference of transfers, is non-trivial. I think the evidence to the extent of climate change whether we have a few suggests that things that have a net economic benefit, wind turbines in my neighbourhood or not. The issue such as energy efficiency, save money and create jobs. is that that is going to happen or not happen, and in I think the evidence suggests that things like the way that is going to happen. The question is renewable energy move jobs around. whether we have the wind turbines that undermine my However, given that a number of countries around the locality, to which the answer is the kind of negotiation world are going after renewable energy and these that Mr Yeo was referring to. green targets in a serious way, the question has to be Chair: The shortcomings of the planning system, for Britain: how many of these jobs we are managing though relevant to this inquiry, are going to take us to make stick here in this country? I would refer the down a track we do not have time to complete. Committee to a recent report on the French plans to develop their offshore wind resource, which they did Q32 Ian Lavery: I was looking at job creation for through a series of tenders. There were a couple of onshore and offshore wind farms, and there is a lot of British companies represented in those tenders, but scepticism with regard to how many jobs have been they have managed to attract straightaway the created or are likely to be created. How many jobs has construction of four new factories in north-west the onshore industry created to date, and what are the France. We are still struggling to persuade Siemens— prospects for further employment in the future? I think it is—to go ahead and build a factory in north- Professor Fankhauser: I don’t know the aggregate east England, even though we are in the lead on the UK numbers. There are statistics that say how labour development of offshore wind. Without getting into intensive, as it were, different types of technology are. arcane debates about net job creation, net job The one statistic I have, which is from a US study, destruction, general equilibrium modelling and the says that coal and gas typically use one job per MW, economy, I think there is a clear need to ensure that if you derate it. Wind is more in the range of 0.7 to more of the real high-end engineering jobs associated 2.8 jobs, so you could potentially have more jobs per with doing this stuff stick here. That is a policy-driven MW in wind than you have in coal and gas, but there situation, because other countries are going after it. are certain dangers in doing that. First, jobs occur at different points in the value chain, if you will, and Q33 Ian Lavery: In the shift to renewables we are wind jobs tend to be mostly in construction and seeing a lot of job losses in the fossil fuel sector. How manufacturing, while coal jobs tend to be a lot in does that compare with job creation in the extraction, so not all of those jobs actually would renewables sector? happen in the UK. Dr Gross: I think the biggest job losses that you are As an economist, I would also point out that more seeing in the conventional energy system result from jobs per MW is the same as saying these are low— moving from domestic coal to imported coal and from productivity, and therefore potentially low-paying, imported coal to gas. There are far fewer jobs jobs, so this is not necessarily something we would involved in running a modern combined-cycle gas want to see. My summary of this question is that there turbine than there were 30 years ago when running a is no job penalty from going to low-carbon, but it is large coal fired power station with a nearby coal mine not obvious that there is a clear job benefit either. supplying it. I think that is to do with a long-run Professor Hughes: Counting green jobs is an technological change in the economy. It is to do with intensely controversial issue. I have written about it the fossil fuel transition that we have seen and it has and the simple answer is that if you look at a very an awful lot less to do with— narrow definition, probably a very small number of jobs have been created. If you look at a larger Q34 Ian Lavery: I am just asking if you had any definition that takes account of the knock-on effects in comparable figures on the loss of jobs in the fossil the rest of the economy, it is clearly negative. Again, I fuel sector and job creation in the renewable sector. will draw locally on a very simple story. We have lots Are there any comparable figures? of wind farms, and we also have, right next door, my Professor Hughes: Historically there is no doubt that neighbour, who is a rather successful health spa. That the loss of jobs in fossil fuels has been much greater health spa is a very small business, relatively than the creation in renewables, but that is not just speaking, but it employs 160 people, which is more because of the promotion of renewables—that is just than all of the wind farms in my local authority, which simply exhaustion. have something of the order of 1.5 GW generating Dr Kennedy: If you look at how much we have capacity in that. That gives you a sense of scale, invested in renewables, it is not very much to date, so because one is from an investment of a couple of just on that fact alone you can’t have displaced many million pounds and the other is from an investment of jobs through what we have done in renewables. It is well into the hundreds of millions. other factors, as both Gordon and Rob have said. Dr Gross: Sam and Gordon are both absolutely right Professor Hughes: But the real problem in the future that the creation of net jobs in the economy is very is not fossil fuel production; it is manufacturing. It is complicated and vexed. You are effectively moving energy-intensive manufacturing where the job losses money around within the economy. You are taking will occur in future as a result of higher energy prices. Energy and Climate Change Committee: Evidence Ev 11

10 July 2012 Dr Robert Gross, Professor Sam Fankhauser, Professor Gordon Hughes and Dr David Kennedy

Q35 Albert Owen: We have talked about economics, Professor Hughes: That the Government have technology, planning and siting, but one thing we have responsibility? Yes. If we are going to go down this not talked about—it has been raised a lot in the route, you would very much want to set up a basis for evidence that we have been given—is the public monitoring and carrying out a long-term study. It will health implications of people living in close proximity take 10 years but, sadly, that is the way it is. to wind turbines. Have there been any comprehensive Professor Fankhauser: I would agree with that, but studies that you are aware of and, if so, what were if you look at the literature of the negative impact the outcomes? generally of wind, what dominates is the visibility, Professor Hughes: The effects are controversial. followed by impact on wildlife—birds and bats in Some people appear to be significantly more particular—and then everything else is a distant third. vulnerable to certain kinds of disturbance from wind Whether that is because— turbines, particularly low frequency noise and a few other things. I would not say that there is any Q38 Albert Owen: I fully accept that, but my overwhelming evidence that there are significant argument is when a large wind farm comes before health effects. People individually may suffer quite planning, it is very controversial—those are the big badly, but I don’t think collectively there is a large issues—but the proposed developer is asked to impact. conduct with the local authority an environmental impact study. They have other impact studies, but a Q36 Albert Owen: Is that because you don’t know health study is not available, and I am suggesting that or you don’t think there is, or is it that the evidence should be given greater weight. is not available? Professor Hughes: It is exactly like the Professor Hughes: There isn’t at the moment enough electromagnetic radiation associated with transmission evidence, such as controlled studies to monitor the lines, for example. It is something that you can only health of people over a significant period of time. It establish by quite long-term monitoring studies. One would be something that would be worth doing but it ought to do that—it has been done in the case of has not, to the best of my knowledge, been done on EMF—and I think that as a precaution you can at a anything other than a very anecdotal basis. relatively low cost do that for wind farms as well. Chair: We have two other panels, I am afraid. Thank Q37 Albert Owen: Do you think the Government you very much indeed for your time this morning. It have a responsibility to do that? has been a very useful and interesting evidence session for us.

Examination of Witnesses

Witnesses: Robert Robinson, Secretary, Montgomeryshire Local Council Forum, Jeremy Elgin and Adrian Snook, gave evidence.

Q39 Chair: Thank you for coming in. We only have nice social things like fetes etcetera. If you look at it 30 minutes for this session, so I will ask my now, what you will find is a breakdown of wind farm colleagues to be concise and that you be concise in applications. So I think when you look at somewhere your answers. As I think you are giving evidence to like the TAN 8 areas of Mid Wales, or if you look at this Committee for the first time, but I will not have Daventry District, you are looking into the future—a a prolonged introduction. As I understand it, Mr Elgin, successful policy, as some would see it. And so I think you have a planning application going in for a wind you need to distinguish between polling data that farm. shows overall a positive inclination towards Jeremy Elgin: Correct; a turbine. renewable energy as a superset and wind energy as a subset, and you need to understand that over the last Q40 Chair: Mr Snook, you are an opponent of an 10 years a schism has taken place. What has happened application in your neighbourhood? is that wherever the public has come into contact with Adrian Snook: I live 485 metres from the nearest the wind energy industry and the process of turbine. application and planning, that positive motivation has vaporised and has been replaced by feelings of Q41 Chair: Mr Robinson, you represent the forum, negativity and fear. That is the overwhelming feeling, which also have concerns about it? as well as hostility, because frightened people do not Robert Robinson: Not this particular wind farm, sir. react in the way that you might like them to. An It is about the Mid Wales situation, which no doubt American jurist once said, “You can’t expect detached will come out as we go along. reflection under an upraised knife,” and that is how people feel. Q42 Chair: Perhaps each of you would like to say So what you have is a situation where half and what you think public opinion on wind power is in possibly more of the population around the country your own neighbourhoods? may well look at onshore wind turbines and see the Adrian Snook: I have arranged for the Committee to same things that I saw five years ago: which is an icon have access to a few pages from the Crick Parish of responsibility and modern, benign technology—all Newsletter. It is a publication that used to be full of of these lovely things. Unfortunately, the good will of Ev 12 Energy and Climate Change Committee: Evidence

10 July 2012 Robert Robinson, Jeremy Elgin and Adrian Snook the British population has been abused and abnormal loads, of three lots in each, over a matter of squandered through a very ill thought-out policy. It three or four years. is the policymakers who brought those choices to a population who are in the dock, frankly. What you Q44 Chair: Is that a proposal that is disproportionate have is a very different picture, where the industry to the— will continually highlight the modest positive Robert Robinson: Absolutely. motivation among the majority of the population, particularly the urban population, and then in areas Q45 Chair: I am not absolutely clear, is it also like Daventry District what you see is a situation envisaged there will be overhead transmission lines where the wells of resentment have overflowed. They resulting from this? have run into each other and now Daventry District is Robert Robinson: Yes. a lake of resentment and unfortunately—I will wind this up—all the studies done by Parsons Brinckerhoff, Q46 Chair: Technologically, it is possible, at slightly Arup, Pöyry et al were working under a greater cost, to bury those. misapprehension. The capacity of the UK for onshore Robert Robinson: This brings us to the point that was wind development is not to do with geography, made by the gentleman on my right: the public feel topography and meteorology; it is to do with the alienated. They have not been involved; they have willingness of the host population to accept what you been talked to rather than discussed. If somebody are forcing upon them. The terms of the offer are came to Mid Wales and said, “The number of turbines absolutely critical. What should have happened in is going to be reduced by x and the cabling is going Daventry District, if in the TAN 8 areas of Mid-Wales underground,” I think you would be talking a different and in Sedgefield constituency, for example. If the story. It is the fact that you have all these bits thrown resource was genuinely as valuable as it was said to into one. It is not just Mid Wales; I know North Wales be, then local people should have been treated with feels the same. I administer the North Wales respect and dignity, and they should have been Association of Councils and they all feel very much engaged with in a positive way with safeguards the same way. meaning that local people would have some Jeremy Elgin: I am obviously on a different scale. I confidence. am just looking to do one turbine. Interestingly, where Robert Robinson: We took a different view in Mid I am trying to put my turbine is right next to an Wales. Here we are not talking about being against existing power line, so we have no issues on that front. renewable energy; we are looking at the sheer scale I find myself in some degree of agreement with the of what is trying to be imposed on a rural community. view of my colleagues. There are pools of people who We have a 56,000 population in Montgomeryshire are vehemently opposed, but the reaction that I have who are looking at something approaching 630 185- had is that there is a much larger—albeit mainly silent, metre-high turbines. With that comes a 20-acre unfortunately—majority who realise that we can no football pitch-sized hub and a 400 kVA line. You can longer carry on with the way we are going. Part of the imagine the feeling in Mid Wales is not that issue is trying to get those people who are in favour particularly favourable, but we could hold a public motivated to make a stand. It is far easier to motivate meeting, and I can just see you sitting there and people to be against something than to be for saying, “How many people turned up?” “500.” “That’s something. excellent, what is your electorate?” “5,000.” Not We are having some interesting discussions. We have terribly representative. What one council did in Mid engaged a lot with the community, but one of the Wales, in particular Welshpool, was a door-to-door problems is that the planning system, by its very survey where the leaflet was delivered and the nature, is adversarial. Before we put our application questionnaire collected the following morning from in, we had to do a terrific amount of work and the the doorstep. This leaflet was seen by the industry and opportunities to try to engage with the community in by the county councils to make sure that it was as the wider aspects were limited. We ended up having unbiased as possible. I can leave with the Clerk the to dampen down the rumours that we were going to detailed breakdown of this, but the nuts and bolts of do this and that—“I hear you are going to put up 50 it are that we had a 42% return showing an 80% turbines.” We were just looking to do one. I was concern at the level and scale of what was being strongly advised, until we got our plans in order, to imposed, mainly because the wind farm companies, keep relatively quiet, which we did, but we have had the county councils, the Welsh Assembly and public consultations and articles in the press and on Parliament, I am afraid, have not engaged with the the radio. Once I get beyond about a kilometre from communities over what they will be prepared to the proposed site, there is significant support. I think accept. that degree of support is reflected in the national polls that we have seen on wind turbines, but my problem Q43 Chair: To clarify, are you implying that if the is trying to get them out. scale of the proposal was significantly less, most of those concerns would be— Q47 Sir Robert Smith: Have any of you discussed— Robert Robinson: I believe that is probably the case. I am really looking at the objectors here—with It is the sheer scale that you are looking at. We have developers how the problems can be alleviated? The wind turbines in Mid Wales already, and there was no issue of scale is a very straightforward one, but are worry when they came. It is the massive infrastructure there other ways in which these threats could be made and, indeed, the transport implications of 7,500 less threatening and more acceptable? Energy and Climate Change Committee: Evidence Ev 13

10 July 2012 Robert Robinson, Jeremy Elgin and Adrian Snook

Adrian Snook: I think one of the problems has been resist. What I really object to is the fact that we are that Government policy over a long period of time has being demonised as “anti-winders” or something. We been very simplistic. It has more or less said, “Let us are not; we are just ordinary people who want a bit of focus on creating incentives for investment and dignity in our life. If these things are built—when they removing barriers to deployment”. Incidentally, in the are built—how do you think people will feel about renewable energy road map, I am described as a non- them when they are lying there at night hearing them financial barrier to deployment, rather touchingly. spin away? The farmer hears money dripping into a Basically, if you do that, if you get the express train bucket; they feel violated. running, ultimately these things will be steamrollered Robert Robinson: We have spent a fair bit of time, in through. It was entirely predictable that there was Mid Wales, talking to National Grid, going to be huge anxiety about it. It is probably the and the wind farm companies. The difficulty we have biggest change to rural land use since the Enclosure come across in each and every case is that we are Acts, and the focus has been basically on preventing dealing with an individual site. An individual site in local authorities zoning for wind turbines, preventing itself is not an issue to us; it is the accumulation of the use of any discussion about the utility or the the whole lot that has caused us a problem. That is practicality of the application as an objection. Of really where it has come from. The one thing that course, existing planning law means you can’t object seems to be insurmountable, irrespective of your view on the grounds of the originator of the scheme. I think on pylon lines and hubs and so on, is the transport the originator of the Yelvertoft wind farm was a fuel issue of trying to bring abnormal loads down roads bunkerage business based in the Bahamas, for example. It does not really matter whether it is a local that are barely the width of one lane of the M4 for property developer, a foreign property developer, or both directions of traffic. The amount of work and one of the big six utilities with a history of doorstep infrastructure that has to be put in on those small roads selling; it really doesn’t matter- there is an absence even to accommodate the first lorry is pretty grim. of trust. That is what, locally, we have had difficulties What happens, typically, is that a developer will come discussing. The conversations have been very good to a village, they will keep their development secret. and helpful, but we have a problem once we try to They will also keep their detailed costings secret and talk about the overall infrastructure. the reasons why they have selected this community. I do know that a transport plan for the whole of Wales They will just say, “It is financially viable for us.” has been prepared, but apparently it is not publicly They will then come and announce their plan. In the available. I wonder why? It is probably because it case of the Watford Lodge wind farm, it was for five reflects the figures—again, I can leave them with the 126-metre2 wind turbines—the same height as the Clerk afterwards—that have been accepted by the turbines at Chedburgh airfield to which you objected, Welsh Assembly Government as correct for the sort Chair, back in July 2007. And after three years of of transport we are looking at, which is something trench warfare, the scheme that has been implemented approaching 630,000 extra vehicle movements on Mid is exactly the scheme that was put forward. I do not Wales roads. We do not get a quarter of that in a year think the Government have fully appreciated the because they can’t fit on them. Yes, we have had good commercial impact of removing local residents’ discussions, but when you start moving away from an ability to say no to an offer. If you are trying to individual wind farm, you have a difficulty and that negotiate with somebody and they are saying, “Look, creates a great problem. our friends at DECC are behind this. This is a national Jeremy Elgin: The one comment I would make is that policy. Resistance is futile. You will be assimilated we are no longer in a situation where there is a no- into the UK energy infrastructure.” It’s very difficult impact solution. We have been told, and we have all to negotiate on that basis. Our hands are tied behind heard, about the number of power stations that we are our back. I did try, in the early stages, to talk to the going to close down and the forthcoming problems on developer about coming up with a mechanism the global energy situation. We have a global whereby there would be some kind of compensation for neighbours—some kind of underpinning that said, population increase. China is now the largest importer “Okay, if your property values are depreciated, or you of energy; it also has the largest national currency do not like the impacts, you can move away”—but reserve. We are going to have to increase and change they are not going to negotiate with me. Commercial the way we generate electricity. We are going to have businesses do not give money away for no reason. to put in new infrastructure, and a lot of the comments They do not make concessions, precisely because you and the opposition will apply, I think, to virtually all have given them carte blanche backing, and I do not forms of infrastructure, whether it be road, rail, airport blame them for that. They are in the business of runways and so on. We have a problem. We all want maximising shareholder value. It is in the nature of to have electricity when we turn on the switch. What the beast. got me going on this, when I first started, was an If you create a banking sector-style, light-touch article I saw in The Daily Telegraph where the head regulation of a sector, fuel it with subsidies and send of the National Grid was quoted as saying the days it hurtling towards the population, you can’t in any of the domestic customer having electricity 24/7 are way be surprised that the population take fright and probably going to come to an end. I find that worrying. If we have to have wind turbines—and I 2 Witness correction: Whilst I did say 126 metres, the proposed Watford Lodge Turbines are in fact stated to be ‘up to 125 think that is a good way of producing electricity—I metres’ in height in the consented planning application. think that is a price well worth paying. Ev 14 Energy and Climate Change Committee: Evidence

10 July 2012 Robert Robinson, Jeremy Elgin and Adrian Snook

Q48 Sir Robert Smith: You are saying it is a price making that available. It is psychological as well: well worth paying. I suppose the question is how that “That’s my turbine; I can see it.” price is shared out between the local community, the council and wider society, in terms of the benefits Q51 Sir Robert Smith: You know that you are and the— getting something. Robert Robinson: Yes, but let us take that a stage Jeremy Elgin: Yes. further. You will be looking, in this room, at the cost Adrian Snook: I publicly welcomed that of generating electricity, the cost of a pylon line, the announcement when the then shadow Energy Minister cost of a turbine. We then have to look beyond that actually announced it and it was quoted in the where you have massive scale in the centre of Mid Telegraph. I think the problem with it is that if this Wales, where it is a small community—its tourism is money is going to a local planning authority, it could equal to farming. They are the two big industries in well have a divide-and-rule effect, or a perceived there, and our view is that putting that amount of divide-and-rule effect, and it could be corrosive on infrastructure in one community will take away from trust. So one of the key touchstones that has been tourism what you are gaining elsewhere. That is not ignored in this whole process is proportionality—the easy to put pound notes on—pound coins; I am principle that those people most adversely affected by showing my age now. I think the scale is the thing we a development should benefit proportionately and are looking at here. actually have a proportional input into the shape of the scheme. The tyranny of the mass seems to be the Q49 Sir Robert Smith: One of the things they are argument that runs: that it is in everyone else’s interest thinking of doing in England is allowing the councils and everyone else in the process needs to be to keep the business rates that come from projects incentivised, and you, sir need to make sacrifices. I like that. have spent a lot of time selling things in my life, and Robert Robinson: The council keeping the business I have to say it is probably the worst sales pitch I have rates—it depends which council you are talking about. ever heard. If you are talking about a county council, I think not. Robert Robinson: One thing that has come through If you are talking about a town or community council, very clearly when we have talked about community I am afraid you have to look at a number of them and benefit in Mid Wales, which I know is always talked say, “Are they capable of dealing with that sort of about separately from the planning system—I accept money?” Welshpool is a very big council, but a lot of that—is that the original proposals in our particular the other community councils in Mid Wales are not areas were to have appointed trustees. We opposed so big. I am not so sure the public would see that any that vehemently and we do now. We believe they more as being bought off, and I am not so sure that is should be elected representatives so that the public, if what they are looking for. Individual wind farm sites they feel that money is not being dealt with properly in themselves are not an issue to us. As I said, it is or where they would like to see it, have a way of the scale that needs to be sorted. If only communities dealing with it through the ballot box. We think that could have clarity very, very soon on what that scale is quite important. is going to be, I think things would quieten down a bit more again, assuming that there is a reduction. At Q52 Sir Robert Smith: Do you think there are any the moment there is this fear that was mentioned of lessons to be learned from Denmark and Germany, what is actually coming. where there is much more community involvement? Jeremy Elgin: I would agree with a lot of that. My Adrian Snook: I have put some recommendations in experience, when we were talking about community my evidence and one of the suggestions I made is that funding and stuff like that, was that it would just there seems to be an inconsistency in the approach. disappear into an amorphous pot and the benefit Moral blackmail is being applied to rural communities would not be identified. What a lot of my neighbours saying, “This is in the national interest. This a national have said to me is, “If I can get cheap electricity, or emergency. You shall comply.” At the same time, electricity at a reduced rate, I would support it.” basically, it is a free-for-all commercial market. There Unfortunately, there is no mechanism where I, as the is a mixed message there and I think you need to have owner and operator of a turbine, can supply electricity some kind of check and balance that says you should to those in the immediate vicinity. If there was a not be treating those people who are making sacrifices mechanism in place to do that, I would see a in the national interest unfairly, and there should be significant increase in the support for the turbine. some kind of mechanism to assuage their fears, if they are groundless, in advance and to compensate them Q50 Sir Robert Smith: Could you not make a if they turn out to be grounded. The Promotion of financial transfer based on their bills? Renewable Energy Act is one piece of legislation I Jeremy Elgin: We probably could. That has been highlighted in the report. I am not saying it is perfect, suggested, but people then started clamming up. I also but that is one area, and the experience in Denmark think this could be a role for the local authorities. All was also highlighted earlier on. local authorities and companies are now saying, “We The problem is we are where we are. We have passed want to increase the amount of renewable energy that a window of opportunity, frankly. The rural population we consume ourselves.” My understanding is that is frightened, they are frightened because of what they local authorities can now sell energy. I think this could perceive to be an alliance between DECC, the energy be a role that the local authority could take on by industry, the Institute of Acoustics working party on acting as a mechanism to take on the electricity and wind turbine noise, Parsons Brinckerhoff, Arup, Energy and Climate Change Committee: Evidence Ev 15

10 July 2012 Robert Robinson, Jeremy Elgin and Adrian Snook

Pöyry—all the organisations that are driving this levels, but at local level there is supposed to be forward. And so they do not feel they can trust a word supplementary planning guidance. Do you think they that any of those organisations or Renewable Energy should be strengthened so that they safeguard local UK says on the matter. Unless you fix that, then the communities? Should there be democratic election? Is fear that exists in the rural communities is going to that a weak link in the planning process, do you think? persist. So in addition, with the recommendation on Jeremy Elgin: It is possibly even the opposite. We a property compensation scheme, and of course the have national guidance, the MPPF, EN1, EN3 and so industry will have no objection to that, because there on. What we are seeing is councils trying to put in is no property devaluation so it will not cost them policies that are diametrically opposed to that. On one a penny. side we have— Robert Robinson: I will give you the shortest answer that you will probably have this morning. I do not Q54 Albert Owen: Could you explain that? Are you think Denmark or any other country abroad has any saying there is not local supplementary planning relevance whatsoever to what happens in this country, guidance in place? so the answer is no. Jeremy Elgin: No. I will give you a concrete example. Jeremy Elgin: I would like to contradict what Mr Milton Keynes are bringing in, or have brought in, a Snook says about the fear and everything else. There SPD—I understand that that is what it is—that will is concern among a section of the rural population. effectively stop wind turbine development within Where I am, there is also a lot of support, as I said, Milton Keynes, or make it extraordinarily difficult. So but it is quiet. He who shouts loudest gets heard most, on one side we have central Government with the and the people who are shouting loudest are the MPPF, and local councils have to have policies in objectors. place to encourage or develop renewable energy, and Adrian Snook: Those most seriously affected. on the other side places like Milton Keynes are Robert Robinson: I would suggest to you that saying, “We are going to bring in this SPD that will although that is a fair comment, with the survey that stop it”. was carried out in Welshpool—there was no pressure; Robert Robinson: If you are going to find a way you did it in the armchair of your own home—we still forward, particularly with Mid Wales—we keep had the same result of objections on the scale that we coming back to the scale—I think it needs decision are talking about. makers to meet with the community councils to see if Adrian Snook: I have huge sympathy for Jeremy there is some common ground that could take us because he is actually the victim. In fact, the energy forward. If that does not happen, I can see opposition industry is a victim because it was set excessive at every stage, irrespective of what the planning expectations by politicians. There was no way they system offers. It is about engagement with local could force this through on this basis across the councils who need to feel they have been engaged country for a dispersed energy system. The political with and not just consulted in a way so that when the damage was just going to be ridiculous. So they were paper comes out, as has been said earlier, nothing has set excessive expectations, but it is not going to say changed or been taken into account. It is this dialogue it, because it are not going to bite the hand that feeds, that is needed to be had, not just over one bit, but over but I will say it on its behalf. Then with Jeremy, the whole conglomeration of putting them all together. unfortunately—people are putting in these outlier applications in small areas. The local population, Q55 Barry Gardiner: Mr Snook, you have painted those immediately adjacent, look at the available a very clear picture of the winners and losers, and you information, look at DECC, and look at all these other gave us this graphic description of yourself lying in bits of information, which all appear to be aligned bed in the evening and hearing the turbines go around, with each other in a coalition of interest. They look at and the drip, drip, drip of the money coming in to the situation in Daventry District where two turbines those who are developing them. But you then used a of similar size were consented—completely phrase that was interesting. You used the word uncontested and uncontroversial, on an industrial “dignity”, and the sense was that there was this loss estate—and then all hell was unleashed with 93 of dignity. What I want to bottom out with you is: if turbines in the planning system within 15 miles. The it is a matter of dignity, I assume that this is something market punishes virtuous behaviour; they punish the that is a point of principle—it is non-negotiable. Or if neighbours of virtuous people like Mr Elgin. Then there is this drip, drip, drip—this is what seemed to when this kind of application is made up, the be the case when we were talking about whether those resolution is, “Kill it. Kill it early.” That may seem who were suffering the adverse consequences of the unfair, but, “Please stop. The industry is very keen—” development also got cheap electricity—how much Robert Robinson: Chair, the question was about the cheap electricity is your dignity worth? comparison with Denmark. We are spending an awful Adrian Snook: First of all, I can hear no turbines lot of time going off the point. I am sorry. currently. I am in the position of many, many people in Daventry District where they have consented but Q53 Albert Owen: The three of you have mentioned unconstructed turbines, and I think the problem is that the planning system. The previous group of witnesses the whole debate has become very polarised. What mentioned it being polarised; you mentioned it being happens is the proposals from developers spring fully unfair in many ways. What can be done to redress the formed and are then presented to the local community balance? We have, as has been outlined earlier, the for consultation. So the turbines were placed where energy companies and the Government at various they were placed and they were the size they were and Ev 16 Energy and Climate Change Committee: Evidence

10 July 2012 Robert Robinson, Jeremy Elgin and Adrian Snook so on. The developers expect opposition and they have couldn’t get on HS2 because it didn’t stop there, so to consult them purely as a planning nicety, really. there is a precedent that would seem—apposite in There was not any material change made, so the net that sense. result is that aspects of these applications are Robert Robinson: The motorway idea brings perhaps unacceptable in many dimensions. Two of the a benefit to a lot of communities. I think what Mid turbines, for example, run across the line of an avenue Wales sees with the sheer scale of it is that the benefits of trees for a place called Watford Court and of course are gained by the few, but are going to affect the that is now a scheduled ancient monument. It is a many. place that has a lot of sentimental meaning for local Jeremy Elgin: I do not think in the much wider people. population there is a full realisation of the issues and Chair: The question was about whether there is the problems that this country is facing with its enough conversation about it. We understand the electricity generation. I think if we could have a lot emotive nature. more publicity about the downside that this country Adrian Snook: The compensation has to be greater if is potentially facing in terms of securing its energy the loss is greater. Do you understand what I am resources, which leads to points about employment saying? Because these schemes are being put forward and so on, we could have a much more open debate. in a thoughtless way without pre-application consultation, the affront to dignity is greater and the Q59 Ian Lavery: I want to get back to employment, emotional response is that much more. very briefly. According to a study commissioned by DECC, onshore wind farms support roughly 8,600 Q56 Barry Gardiner: I understand, but what you are jobs and bring in £550 million to support the UK saying is, “Let’s have pre-consultation and, in a sense, economy. Do you have any evidence of this? an ongoing negotiation so that we can bottom out how Jeremy Elgin: Yes. I am going to throw in one other much the grove of trees is worth,” and so on. But isn’t slight curveball on this one. Many companies now do that precisely what this Government have tried to put environmental audits and have green policies about an end to—these interminable planning decisions, the energy that they produce with their manufacturing discussions and negotiations meaning that nothing process. In fact, there is now an additional standard ever gets built? When you are dealing with something called WindMade for which companies with a as important as electricity generation, which we all percentage of their energy requirements generated accept—Mr Elgin spoke about when you switch the switch on you want the electricity to be there—how from wind can apply. Consumers and investors are are you going to get around the problem of now taking these issues very seriously and I think that interminable negotiations over single generators in companies looking to invest in the United Kingdom different parts of the country stopping what the will increasingly require a green energy generation national priority of keeping the lights on? capacity as a pre-requirement for that inward Adrian Snook: I think the publicised comment by the investment. Member for South Suffolk— Robert Robinson: The suggestion was made that if Chair: Me. Mid Wales needed to have a fairly large number of Adrian Snook:—about the need for a bribe was turbines—or indeed anywhere around Wales or the insensitively put, if you don’t mind me saying so sir, UK—they could perhaps be made on site, which but the fact that after all these years of energy policy would remove the big transport issues that come with formulation the actual balance should be too far out it, and the answer came back from Parliament that of kilter for that blunt instrument to be used is an there was not the expertise to do it. I would suggest indictment of the policymakers. So, yes, we are in a that the very first wind turbine didn’t have the bad place. For all concerned we are in a bad place. expertise to do it either, so I don’t see why that could not be the case and, again, that would give a much Q57 Barry Gardiner: But I am asking you for a longer term employment benefit. Looking at the solution. I think we can all accept we are in a bad turbines that we have at the moment, there was an place. employment benefit—some of it locally, some of it Robert Robinson: The solution comes with what I not—when the turbines were being built, but once said a few moments ago: involving the community they were built the actual employment benefit was with decision makers so that collectively you can very small. come up with the best for the community, taking both sides into account, rather than having this standoff that Q60 Ian Lavery: If there were more jobs being seems to happen on each occasion. Of course, when created, would that mean there would be less public you get a standoff, that is when the planning system opposition to the wind farms? has difficulty coping. Robert Robinson: It would go into the mix. I am coming back to this consultation with the group of Q58 Dan Byles: Is it different to any other planning community councils. That could go into the mix, a issue? Is this different to a motorway, a road or a subsidy could go in the mix, and then you could come factory? up with an agreed way forward. This could be done Robert Robinson: No. in three months, and then you would have a chance Adrian Snook: It is in a sense that you can access the of seeing your renewable energy policy in Mid Wales motorway normally. HS2 is an example where it was moving forward with some public backing, but you deemed to be in the national interest. Local people are not going to get that unless all this is put together. Energy and Climate Change Committee: Evidence Ev 17

10 July 2012 Robert Robinson, Jeremy Elgin and Adrian Snook

Q61 Ian Lavery: Would there be less public Robert Robinson: Yes, that is the idea, but then there opposition to wind farms with more jobs being is also the ongoing maintenance after roads have been created? knocked about and then reinstated, and we all know Robert Robinson: Possibly. I wouldn’t like to say how how they do not go back. We are also left with a much less opposition there would be, but there would legacy of corners that look as though they have been certainly be less opposition because it would reduce chopped off for giant lorries but are never used any the amount of transport that was needed. more. We also have the issues that seem to be ignored Jeremy Elgin: I think an internationally recognised of local knowledge, and I particularly refer again to viable energy generation and supply infrastructure the Welshpool area because they have a thing called within the United Kingdom will obviously attract the Leden Brook and it lies underneath the road. I significant numbers of jobs from investors looking to don’t care how many wheels you have on your lorry come to the UK. Companies will look at this when for axle-loads; that is likely to collapse, and yet we they are setting up their manufacturing operations are told, “Oh, no, that will be all right because the with an increasing level of priority, I think. load is spread”. Adrian Snook: I think one of the interesting case There are also implications regarding large lorry studies could be provided by the Member for Ynys movements down narrow main streets and places like Môn in the sense that if you look at what is happening Llanymynech on the borders between England and in Anglesey, what you have is a nuclear power station Wales is one of these places where the buildings are that locals desperately want new investment in. 150 to 200 years old. They are right up to the street, Albert Owen: Not everyone. and with lorries going past on a continual basis, if the Adrian Snook: Well, many of the people want it. weather conditions are not right that earth will move, They have a situation where they have an aluminium and you will then end up with structural problems. smelter that is not operating and they also have a large Who is going to pay for that, because insurance number of applications for largely unwelcome wind companies won’t? You have issues surrounding the turbines, so it is a very difficult balance to be struck aspects of that as well. between all of those various elements. Adrian Snook: I didn’t fully answer the question that the gentleman3 asked me and I just wanted to say Q62 Sir Robert Smith: May I ask one quick that the prerequisites for a solution are the question of Mr Robinson? You were mentioning recommendations in my evidence. transport during the construction phase. Does the Chair: Thank you very much indeed for your time developer have to bear the cost of improvements to this morning. It has been very helpful. the road infrastructure that are necessary during that 3 Note by witness: gesturing towards Barry Gardiner and transition? referring to question 57.

Examination of Witnesses

Witnesses: Sarah Merrick, UK and Ireland Government Relations Manager, Vestas, William Heller, RewewableUK, and David Handley, Chief Economist, RES, gave evidence.

Q63 Chair: Good morning. Thank you very much it would go from 1 to 0.9. To change that, as David for coming in. I think you have heard some of the said, without any consultation or evidence would be earlier evidence. In view of the pressure of time, I will devastating in terms of how people would view dispense with formal introductions—we know who making investments in the renewable industry—not you are, and I think you know who we are. just for onshore wind farms, but all investments. Could I start with a general question about the current Sarah Merrick: Can I add here that the evidence debate on ROCs. If there was a reduction below 0.9— suggests that 0.9 is the level that the ROC band should I think we are going to get an announcement very be and I think it is particularly worrying that there soon—will that make a difference to the profitability seems to have been an impression that you can keep of this industry? regulatory risk in one section of the wind industry? David Handley: I think, yes, it will make a As a manufacturer that works across both sections of fundamental difference. There is an evidence base for the industry, if the same developers and investors a 0.9 setting of the ROC banding. Moving below that work across the two, and if you introduce the sort of sends a very damaging signal to investors—to onshore level of political risk to the renewables obligation and wind developers such as ourselves—which means that potentially other support schemes, it sends a very we will not be able to invest, first of all, and that we worrying signal to the whole of the wind industry. will have to rely on either other higher cost low- carbon technologies, or we have to import more gas, Q64 Chair: We have been told two things. One is with the increasing costs associated with that. that the cost of wind power is going to come down— William Heller: There will be a large impact. The no less an authority than the Committee on Climate consultation that the industry just went through was Change says by the end of this decade it will be whether we could reduce the ROCs from 1 to 0.9. competitive with gas. Secondly, we were told a couple We and the rest of the industry have basically made of hours ago that some individual schemes are much decisions and made investments on the likelihood that more profitable than others. If there was a reduction Ev 18 Energy and Climate Change Committee: Evidence

10 July 2012 Sarah Merrick, William Heller and David Handley below 0.9, wouldn’t that do two things: spur the faster William Heller: Our company operates across Europe movement down the cost curve, because businesses and we target more or less the same rate of return tend to respond to these situations; and focus, as under very different regimes. In the United Kingdom seems rather desirable, developments in the most the system here is that the developer pays for virtually profitable places? all the secondary costs, whereas in places like William Heller: You may lose some individual wind Germany they don’t, so you can’t just compare the farms by going from 0.9 to 0.75, but that really isn’t level of the tariff; it is an all-in. As I said, returns are the point. The point is that investors—people who put relatively similar across most of the major European up the financing—will basically see greater risk and markets for onshore wind. stop investing. Our company operates right across Europe. To the extent that we don’t see certainty here, Q67 Chair: Given the importance—and we have we will just basically invest elsewhere, and therein certainly heard this from other investors—you attach lies the problem. We have made significant to certainty, which are the countries that have a more commitments based on 0.9—based on what the stable and predictable policy regime, if any? consultation was—and just to change it at the last David Handley: I think Germany is a very good moment will have significant impacts. It is not just example of this. I think in Germany there has been what wind farm gets built or what does not, but stability within the regime and now that they are whether people will be willing to invest overall in introducing a change to their regime, similar to the this industry. EMR proposals that we are going through, they are David Handley: To add to that, I think we have seen keeping the old regime open to investors until they the costs come down, which is why we have moved get confident with the new regime and making sure from 1 ROC down to 0.9, and that is a very evidence- there is that sort of to-ing and fro-ing that is eligible. based banding level. If you reduce it further than that, you are creating a false economy, because you are Q68 Chair: Do investors in the nuclear industry making a trade-off in terms of the delivery of onshore regard Germany as a country with stable policies? wind, which is the cheapest technology, with higher David Handley: Apologies, I was concentrating on cost technologies or increased gas imports. the onshore wind and renewables industry.

Q65 Chair: When will the wind power be weaned Q69 Dr Whitehead: There are arguments that wind off the subsidy regime, if ever? power companies should bear quite a lot of the costs Sarah Merrick: Are you talking about onshore or of grid extensions, additional transmission costs and offshore? the costs relating to providing back-up for intermittent Chair: Let’s start with onshore. wind power. What is your view about that, and what do you think would be a fair proportion of the costs Sarah Merrick: I think there is evidence that costs are that might be borne? coming down. There is also the fact that as gas prices William Heller: The cost of grid and transmission is and carbon prices increase electricity prices, the actually quite clear—the developer pays for virtually differential that wind needs will obviously come all of it. They pay 100% of the cost to build to a local down, too. I think for offshore, as has been spoken substation where the transmission network exists. about already today, a lot of work is going on within They are expected to pay approximately 85% of any the industry to get costs down to £100 per MWh. reinforcements in the general area. The other 15% is When you talk about weaning off subsidies, it is very considered benefits to the transmission network, so the dependent on the electricity price. split is about 85:15. They are supposed to pay 100% William Heller: Currently onshore wind farm of the cost of large transmission networks across the economics compare favourably with nuclear when entire United Kingdom, which is why the costs in the you are doing all-in costing, so it is a question of what north of Scotland are much higher than if you have a level it needs to come down to, but onshore wind is renewable project in the south. From our perspective fully competitive with nuclear at this point. as an industry, we are paying full fare, if not perhaps David Handley: To add to that question, it is very more, because our perspective has been that the important to recognise that gas prices have trebled charging allocation for what is called “use of system” since 2000. If they carry on at that same rate of is penalising projects in the north, where most of the increase, it is very likely that we will see cost- wind projects are currently placed. So, the perspective effective onshore wind by 2015/2016. Certainly is we are paying full fare and perhaps even more. onshore wind is cost-effective in places like Chile and Turkey, and it reaches grid parity in those countries. Q70 Dr Whitehead: There have been some suggestions that, for example, as wind penetrates to a Q66 Chair: What about other countries? Which other greater extent into the overall capacity of the country countries offer different levels of support for wind as a whole, the power that operates to back up that power? greater penetration operates at a lower efficiency, and Sarah Merrick: There is a very wide range of levels therefore should be compensated for that low of support, but I think it is important to look at what efficiency by wind. Is that a fair argument? the developer pays within its project. In the UK William Heller: In the first panel of the morning, one developers pay for transmission charges and other of the gentlemen was talking about that. The costs of charges as if they were any other generator. That is back-up, as you said, are quite small. Some of the not necessarily the case in other markets. studies are talking about very large numbers. They are Energy and Climate Change Committee: Evidence Ev 19

10 July 2012 Sarah Merrick, William Heller and David Handley talking about how much it costs to back up a wind within the realm of scale of installation and better farm with a gas turbine. That is clearly not the way arrangements? the system operates, but system-wide studies have David Handley: I think, from our perspective, that shown that costs of back-up are quite small right now long-term vision and long-term political certainty are and are not going to rise very much. the key things for driving investment. If we can get David Handley: Certainly from our perspective it is the investors in, we can get the costs down, and that very clear that the costs that are included within would be to everybody’s benefit. reports like the Arup report that feed into the RO Sarah Merrick: Going back to the Crown Estate’s banding are a very complete cross-section. It is very pathways report, it is very clear in that, and the Cost easy to use incorrect assumptions and a simplistic Reduction Task Force Report, that there are decisions model to create a false conclusion about how these all the way along the supply chain with developers costs may or may not change over the future. and investors. In order for those decisions to be made, However, robust studies from places like the National and to make the investments that are needed to drive Grid, Climate Change Committee, Pöyry and costs down, everyone in the supply chain, investors Redpoint, which have the detailed models, show that and developers need to have that long-term visibility these costs are minor to insignificant. of what the market is going to be doing and what the volumes will be. I think, without that confidence, that Q71 Dr Whitehead: What does the projected cost it is going to be difficult for those cost reductions to reduction—we have heard of perhaps 30% by 2030 be delivered. for offshore wind—look like in terms of round 3, and indeed possibly beyond round 3, where the assumption will be that turbines will be placed in ever Q75 Dr Whitehead: On the subject of the Crown deeper waters? What is the loss of competitiveness Estate, just briefly, do you think that the system—the and cost reduction of deeper waters as a metric related Crown Estate charges a licence fee to offshore, makes to the overall cost reduction curve that is likely to be money and gives it to the Treasury, and then the achieved as far as offshore is concerned overall? Treasury provides you with a renewable obligation— Sarah Merrick: I think, in terms of the Crown is anything to comment on, or is that a perfectly Estate’s cost reduction pathways report, there was reasonable system as far as costs are concerned? seen that there was a trade-off between slightly higher Sarah Merrick: It seems reasonable. I have not heard costs going further offshore because you get far higher anyone raising any substantial concerns. wind speeds offshore, which compensates. William Heller: It is consistent with the overall approach within the UK that the project developers Q72 Dr Whitehead: Is that a straightforward pay the full cost and so the total amount of relationship or, as I suspect, rather more complicated? compensation available reflects that. If you go to Sarah Merrick: I suspect it is rather more Germany, where a lot of the costs are covered complicated, but broadly there is a trade-off. There is centrally, and transmission and connection to the a reason why they would be that far offshore and that network are free, it is a very different approach. Here is to capture the higher wind speeds. we are basically saying pay for everything, including access to Crown Estate property. Q73 Dr Whitehead: So you would say the curve is, broadly speaking, valid with marginal perturbations, Q76 Dr Whitehead: This is rather a speculative rather than a substantial loss of cost reduction as a question, I guess. Are you seeing, as more offshore result of deeper water? wind is built, the development of opposition levels to Sarah Merrick: Certainly the Crown Estate report that offshore wind beginning to emerge? Is there an would suggest that. emerging view that the idea that offshore wind’s David Handley: I think one of the panel members competitiveness was particularly based on the fact that earlier suggested that potentially it was possible for it was not onshore might thereby be eroded? offshore wind costs to come down to such a level that you therefore didn’t need onshore wind, and I think Sarah Merrick: I think we have seen difficulties that that is a very dangerous assumption to be making. some offshore projects have had, particularly around There are some real cost savings to be made, but there the onshore substations. I think there is a concern that is a risk about how deliverable they will be and over consenting is quite a challenge for offshore, and the what time schedule. We would need to work very perception that putting things offshore and consenting hard. Achieving those cost reductions is going to be is not an issue clearly is not true. Both London Array very dependent on policy and the level of political and Dudgeon have had considerable difficulties commitment, and we can’t sacrifice onshore wind on getting planning for their onshore substation, and the presumption that those cost savings are going to there is clearly a very robust and thorough consenting be there. regime in place for offshore, as well there should be. I think in terms of concerns within the industry, there Q74 Dr Whitehead: Do you think there are further are concerns about the ability for the consenting things that the Government could do in terms of regime to deliver according to the time scales that are policy initiatives that will assist that cost reduction set out and, in terms of the industry’s development, process? Are there any things you might identify, or those sorts of delays could pose a risk to the is the cost reduction process in your view entirely deployment of the sector. Ev 20 Energy and Climate Change Committee: Evidence

10 July 2012 Sarah Merrick, William Heller and David Handley

Q77 Dr Whitehead: Are you experiencing William Heller: We have looked at those. We have development of specific groups, for example, that two different sorts of programmes within our have been set up to oppose offshore? company. One is to build a community turbine along David Handley: I think the opposition groups for with the wind farm that we are building. We have offshore wind are probably less orchestrated and less done one and we have two others that are now going organised. I think there are opposition groups that are through the planning process, but what has happened having an increasing voice. I would probably say there is that before the feed-in tariff it was very difficult for is less of a concerted campaign from the offshore local communities to be able to put together the sector. However, it is probably increasing, I think, funding and build their own turbines. So what we did given time. in one of our firms was we went for planning for 14 machines, and then we helped the community get the Q78 Sir Robert Smith: We have discussed with the 15th turbine approved, because we had done all the other witnesses the balance of benefits and costs of EIA work, and we basically lent it to them and then onshore wind particularly, and obviously there is a when they had that planning permission we basically benefit to society of low-carbon generation and a built the machine for them. We operate it for them, benefit of more generation on the system, but the costs but they own it and get the benefits of it. Elsewhere— are in the local community of impact on the this is on four other wind farms that we have—we sell environment and the impact on those living close to to the local community, again with a perimeter around the turbines. I think, Mr Handley, your company said it, the ability to buy into the wind farm and basically in its submission that you have come up with, or are own a piece of it. It is essentially a debt product—it looking at, innovative ways of trying to reward the is FSA approved—and it has been very popular. We community. Do you have any examples of these, and have 2,500 co-investors in Scotland investing in our how effective they have been in engaging the wind farms, so for every wind farm that we do, we community? either do a community machine or we do this direct David Handley: First and foremost, it is very community investment in the wind farm. important to stress that community engagement and dialogue with the local communities has to be and will Q81 Sir Robert Smith: Are there any improvements always remain the best way of approaching this. We that can be made in the structure of the renewables then look at things like community funds and we are regimes to make it easier for the community to be very supportive of things like the Local Government involved? Finance Bill, which would hopefully put more funds William Heller: I think the biggest improvement was through to the local communities. In terms of moving to have a feed-in tariff for a single machine. The things forward, we have undertaken polling in terms reason that we did this community turbine attached to of what would be most attractive to the local our farm is that they had all the volatility, so they communities that we are operating in—whether it therefore could not really get good financing on it. If would be things like community ownership, shares it was a fifteenth of a wind farm, it made it a lot easier, within the wind farm company or discounted but with a feed-in tariff with greater certainty, a local electricity schemes. We are in the process of trying to community or individual can now probably get launch a pilot discounted electricity scheme where the reasonable financing terms and can build a single discount is effectively to each household independent machine. That was not the case several years ago. of their electricity supplier within a certain radius of the wind farm. All the indications are that this should Q82 Sir Robert Smith: Do you think anything more be very positively received by the local communities could be done in terms of compensating by looking at we are operating in. the fall in values of property prices near to wind farms and compensating the owners? Q79 Sir Robert Smith: Have you found any William Heller: There have not been a lot of studies, administrative barriers to achieving that? but the studies that have been done have concluded David Handley: Certainly, and this is part of the that there has been no fall in housing prices. There is reason why we are doing it as a pilot scheme. We a lot of uncertainty during the planning process, but a have found very significant administrative barriers, planning process can take five or six years, so people not least in just making sure that we do not fall foul are very worried at that point. of the Bribery Act, as an example, to try to make sure that this is administered fairly and independently, that Q83 Sir Robert Smith: Sort of a planning blight. there are no catches and that it is eligible to all William Heller: Yes. As I said, there is the uncertainty households. That is part of the reason why it has taken of whether it will be built and how it will look when quite a number of years to try to pull this together and it is all done. But the studies that have been done actually get it off the ground. after the fact have concluded there has been no fall in housing prices by building wind farms in a local Q80 Barry Gardiner: Is that tapered? In terms of community. the radius, as you go further from the scheme, does David Handley: To add to that, the uncertainty created the discount become less? If not, you are going to through the planning process is a real issue, and I have a cliff effect, aren’t you? think that goes for all infrastructure developments. I David Handley: Yes. I would need to get back to you. think the solution to that is streamlining the planning I can provide precise details to you, but I would need process so that uncertainty is resolved as quickly as to get back to you with those details, if that is okay. possible. Energy and Climate Change Committee: Evidence Ev 21

10 July 2012 Sarah Merrick, William Heller and David Handley

Q84 Dr Whitehead: I have a request for information. the supply chain has the confidence or the long-term I wonder if you could supply the Committee with visibility that it might need. Where the UK is likely information about, or point to calculations that relate to go in terms of supply chain, there is very good to, the portion of the cost of supplied electricity that evidence that there will be a lot of supply chain jobs is represented by the Crown Estate licensing of your created in the UK and jobs more widely in terms of offshore farms. servicing and construction jobs. I think the UK is very Sarah Merrick: Yes, we could do that. well placed to reap the benefits of that.

Q85 Dr Whitehead: Do you have an indication of Q90 Chair: That does not really rest very easily with that at present, or is that something you could supply? Vestas’ decision last month, does it? There is great Sarah Merrick: I certainly do not have one to hand. I opportunity, but you are pulling out. am sure we could speak to someone about it, yes. Sarah Merrick: I am not able to comment in any more detail. Q86 Sir Robert Smith: When you are doing your applications and considering the impact of your Q91 Chair: I realise there is a legal difficulty, but it development, how much do you look at the additional is hard to reconcile what you said, whatever the infrastructure required, such as the pylons and the reasons are. Here we are: a world leader in generating traffic on rural roads? the thing, with big export markets as well as a big David Handley: Things like pylons and road traffic domestic market, and a massive amount of licences are a very large substantial part of the environmental being offered and applications that have been impact assessment that every developer will carry out. approved, but actually no one wants to build anything. We spend an awful lot of time trying to devise the David Handley: I think this largely comes down to most effective transport routes and communicating the political certainty as well. The level of change that with the local communities about transport issues to the industry is going through with the EMR is very try to minimise any disturbance on them, and that is substantial. We are not direct investors in terms of a very fundamental part of the whole planning plant and equipment in the supply chain, but if I was application process. in that position, I would be waiting for the outcome of that and waiting to see what the political fallout of Q87 Sir Robert Smith: From your experience of the things like the ROC banding decision is going to be different planning regimes within the United before I would be prepared to make any lengthy Kingdom, do you think there is any best practice that commitment of further investment. can be learned from one nation in the UK by another? William Heller: It is a matter of certainty that there is David Handley: In terms of the details of planning going to be a very large global market—no one permissions and planning applications, that is disputes that. It is a question of making investments probably beyond my remit. I am more on the financial in the supply chain, which are generally 20 to 25- and economic side of things. We can certainly get year investments, and people, having gone through the back to you with some details on that. ROC consultation and EMR, have a lot of uncertainty William Heller: Were you saying within the United in the market, so it is difficult to say “Are you willing Kingdom or compared with other countries? to put a several hundred million pound investment down for a 25 year return?” Q88 Sir Robert Smith: Different parts of the United Kingdom obviously have different planning Q92 Chair: Is it really your view that the regimes—Scotland, England, Wales. developments that are planned and the reliance that William Heller: We operate in all the regions. They the Government are placing on a huge contribution are not that different. Scotland has larger planning from offshore wind are not going to happen? regions and so what you tend to have within a council William Heller: No, the opportunity for large is more specialisations. You will have some people investment is ours to lose. We should be the natural that become experts within the area of infrastructure locus for offshore wind globally. or renewables even, whereas in England the planning David Handley: I think it is very important that the regions tend to be much smaller. There is nothing that findings of the CBI report, published last week, can really be done about that; that is just a structural showed exactly how the green economy was growing issue. But as I said, we don’t see massive differences and that it was export-led growth. I think that is very across the United Kingdom. Some areas are more encouraging. That shows that there is the opportunity, difficult than others, but that is not a function of the and there is the opportunity, as William said, to lose. planning process. Sarah Merrick: I think as well, even from Vestas’ perspective, the UK offshore market is still the leading Q89 Chair: Britain is now a leader in offshore wind offshore market globally. generation. Good. This is going to be quite a growing market internationally. Other countries are getting into Q93 Chair: From our point of view, it seems it quite heavily, including China. Why aren’t we doing frustrating that here we have this potentially great better in the supply chain? industry on the doorstep. We have a lot of expertise. Sarah Merrick: I think although the UK is a leader, as Some of the technology that was developed for the we discussed earlier on, wind, and especially offshore offshore oil and gas industry has some applicability wind, is at very early stages. More generally, there are for offshore wind when you go out into the deeper issues to do with the investment climate and whether water and so on, yet we are sitting around saying, Ev 22 Energy and Climate Change Committee: Evidence

10 July 2012 Sarah Merrick, William Heller and David Handley

“Well, because there is some uncertainty about EMR Q96 Barry Gardiner: This report that was done for we are not going to do anything until we know about RenewableUK has a huge variety of direct jobs that.” Here is a great global industry, which we are created—from 1,800 on the central estimate of 13 GW currently potentially a leader in, and we are saying right up to 42,400 if you envisage going to 31 GW. Is “For goodness’ sake, don’t let us take this that really credible—42,400 new jobs? Shell came out opportunity.” and said that there is a risk that public subsidies in Sarah Merrick: I think there is a real issue about, as renewables will end up going to Asian manufacturers. we have discussed at length, the level of confidence They think it is going to be built elsewhere. people have in the investment environment that there David Handley: As the previous panel were alluding is and whether or not that enables people across the to, there are a lot of complexities when defining or whole supply chain and the investment community trying to define and predict what job creation is going and developers to make those long-term decisions. At to do over the next 20 years, but if you have real the moment it is very difficult to see that there is much growth in a sector such as onshore wind, such as visibility in terms of what is likely to happen beyond offshore wind in the renewable sector, then those will the end of the RO, which I think does make it very create a lot of jobs. The scale of the deployment that difficult for investors to make those long-term we are talking about of over 30 GW will generate decisions. That is not just developers; I think it is these levels of employment there. So, yes, it is across the whole— realistic and I think that has been supported by the evidence, which is showing increasing growth over Q94 Chair: Do we need the passage of the the last couple of years in the renewable sector. legislation and the announcement about contracts for William Heller: If I could just say one thing about difference and so on before anyone is going to do the Asian imports. The turbines basically come out anything, in effect? of Europe. Europe basically deploys European-made William Heller: I don’t think we need the conclusion. turbines because they are higher technology. There are What we need is to have the industry feel that it is lower-cost machines available but there are, as far as moving forward in a proper manner and that we will I know right now, no Asian turbines operating in get some reasonable conclusions from the process. We Europe. There are very few of Indian manufacture. do not have to have all the answers right now. They tend to be more of a commodity. They are Sarah Merrick: I think there is a lot of work going cheaper but they are not really designed for the sort on within the industry, certainly off the back of the of conditions that we have particularly in Northern Cost Reduction Task Force and the Crown Estate’s Europe, which requires much higher levels of pathway study. The industry is looking at how it can technology in the machines. So the European industry work much better together in terms of developing is holding its own very, very well. alliancing strategies and what it can learn from the oil and gas sectors so that we can get the costs down and Q97 Barry Gardiner: You do not think that it is just we can put the industry in a position to deliver. a matter of time? William Heller: The whole industry is moving and so Q95 Sir Robert Smith: Obviously there is the read- there is a lot of innovation going on. Europe has a over of technology from the oil and gas industry to significant advantage. They are not going for the the further offshore and construction side, certainly, generic machines. No, I do not believe that we are but there is the challenge that globally both industries going to be basically in a generic machine are facing a skill shortage, an expertise shortage and environment. There is too much value in capturing the a resource shortage, and also that the cash flow of an maximum amount of wind in what are very good wind oil and gas contract is very different from the cash conditions but are complicated wind conditions, flow of an offshore wind project? particularly in Northern Europe. So, no, I don’t Sarah Merrick: Skills is obviously a big issue that the believe they will catch up because the advanced industry is working very hard to address. I don’t know machines will continue to advance. enough of the detail about oil and gas, but I certainly David Handley: Just to add to that, it is very know that the industry is working very hard to see noticeable that that comment came through from Shell what contracting structures it might be able to when our gas imports are probably increasing and replicate that might benefit offshore wind. going to be an increasing part of our balance of David Handley: It is an industry-recognised issue— payment exposure over the next 10 to 20 years. So, skills shortages—and it is something that the industry, we have imports. At least by investing in wind, we whether it is onshore or whether it is offshore, is have an upfront hit at the moment and we can working very hard to try to tackle. We are engaging hopefully develop a supply chain to minimise imports, with local universities and schools. We are trying to but after that the resource is there and it is free. get engineers, showing them what they can be doing, Chair: Thank you very much for your time this getting them out to site and really trying to morning. It was very helpful. communicate with them so that we have got these engineers coming through the skills gap. Energy and Climate Change Committee: Evidence Ev 23

Written evidence

Written evidence submitted by Adrian J Snook What methods could be used to make onshore wind developments more acceptable to the communities that host them? Executive Summary Proposals for new large-scale onshore wind energy developments in the UK often encounter stubborn resistance from local people that regard the current economics of wind farm planning, development and operation to be inconsistent with the principles of proportionality or fairness. Urgent action is needed to redress the balance of benefit against harm and to restore the faith of the rural population in environmental safeguards.

Reasons for UK Resistance to Onshore Wind Development 1. A global list of 242 countries listed by population density reveals that the UK ranks at number 52 with 62,041,708 people, crammed into just 94,060 square miles. 2. The British feel they have a special cultural affinity with the remaining open countryside, commonly regarded as a precious national asset to be conserved rather than a hostile wilderness to be tamed. This is evidenced by the support for popular organisations like CPRE, CPRW and Rural Scotland. 3. This cultural affinity with open countryside has been reflected in long established political priorities and enshrined in planning policies such as PPS7, which stated that the Government’s overall aim was to “protect the countryside for the sake of its intrinsic character and beauty, the diversity of its landscapes, heritage and wildlife, the wealth of its natural resources and so it may be enjoyed by all.” 4. Home ownership has long been an emotive and important political issue in the UK with around 68% of the population owning their home according to 2010 figures. 5. For decades residential properties in rural settings has attracted a premium in the property market for cultural reasons and because the long-standing “presumption against development in the open countryside” acted as a safeguard against adjacent industrial development that might give rise to potential price depreciation. 6. Due to the desirability of rural properties and the associated price premium, older citizens have tended to rely on their investment in their home as a key vehicle for retirement planning. 7. Proposals for the construction of an adjacent industrial wind farm usually come as a huge shock to local people, giving rise to legitimate fears of significant financial loss arising as a result of blight and property price depreciation. 8. The wind energy industry repeatedly asserts that wind turbines will have no effect on property values but the research on this issue is far from definitive. Properties that originally attracted a premium pricing for their rural setting are clearly likely to lose that premium when turbines are in close proximity. 9. Unlike the case of HS2 there are no statutory arrangements for compensating local residents that incur significant loss or exceptional hardship as a result of adjacent industrial development by the wind energy industry. However as in the case of HS2 wind energy infrastructure development is usually justified by a claim that this is in “the national interest”. 10. The paper by Breukers, S. and M. Wolsink (2007) “Wind power implementation in changing institutional landscapes: An international comparison Energy Policy 35, 2737–2750 points out that the five Non Fossil Fuel Obligation NFFO orders (1990–98) applied a highly competitive tendering system, which awarded contracts to those that offered to develop wind projects at the lowest cost. 11. Serious competition meant that companies with strong financial backing—often subsidiaries from the energy or construction sector—were usually in the best position to obtain contracts (p. 2741). Breukers and Wolsink also imply that UK energy policy continued to favour large developers, especially those related to the large utility companies, after the introduction of the Renewables Obligation in 2002 (p. 2743) 12. This apparently had two unfortunate consequences. Firstly this discouraged community-led wind because local people lacked the resources needed to develop wind energy under the rules of the UK energy system. Communities could not exercise power directly over the siting and design of wind energy developments as they might have done had the community itself been the developer or a partner in the development. 13. Secondly, the financial pressure on developers to deliver wind energy at lowest cost may have contributed to their failure to appreciate local planning, environmental and landscape issues (McKenzie Hedger, M, 1995. Wind power: challenges to planning policy in the UK. Land Use Policy 12, 17–28). 14. It seems that UK wind energy policy has consistently favoured major energy businesses, resulting in the power of people in local communities (who have the most obvious stake in onshore wind energy siting and design) being limited in a way they often feel is inconsistent with the principles of proportionality or fairness. Ev 24 Energy and Climate Change Committee: Evidence

15. Local people are usually excluded from the site selection and initial design stages of the development process. 16. Developers have generally minimised the benefits they offer to local people precisely because they enjoy “carte blanche” backing from central government. In some cases this backing led them to believe that central government policy alone would ultimately force their developments through, making significant financial concessions to the local population unnecessary. 17. The income that would otherwise have been shared with local people is either earmarked as potential profit or contributes to inflation in a spiralling market for an ever-shrinking number of suitable wind farm sites. The result was an even greater cash “wind fall” for wealthy (often absentee) landowners and investors. 18. The resulting community hostility has been aggravated by the sale of all of our domestic energy providers to foreign parents and the gradual collapse in consumer trust in major energy businesses following incidents like doorstep mis-selling. A recent Reputation Survey on Energy providers shows a worrying trust deficit towards the “Big Six”. 19. The extraordinary rhetorical support and practical assistance offered to the Wind Energy industry by successive ministers at the Department for Energy and Climate Change (DECC) has contributed to a growing breakdown in trust between the department and wind farm neighbours. Unfortunately ministers are increasingly perceived to be too close to the onshore wind energy industry to be trusted to look after the interests of ordinary people. 20. As a result, repeated assurances from the DECC regarding the efficacy of environmental safeguards relating to noise, shadow flicker or the environmental utility of wind energy are increasingly ignored by a rural population who are turning to other independent sources of information on the web for “alternative” information. 21. Thanks to energy-switching websites, yesterday’s compliant power consumers are today’s empowered customers. They have become accustomed to rejecting financially unattractive business propositions from the energy sector and they do not understand why any power provider should be able to force a wind farm on unwilling local people. 22. Rather than promoting community-led renewable energy schemes that offer local people worthwhile personal benefits proportional to the negative impacts, successive administrations have incrementally tilted the planning balance so that the construction of onshore wind turbines by big business has became “an offer you can’t refuse”. 23. People living close to proposed developments feel obliged to resist because neither community benefit funds nor the retention of business rates will proportionately compensate them for the personal negative impacts that will arise. 24. Planning law makes it impossible to lodge a planning objection on the grounds of the identity or status of the applicant, their past behaviour, or commercial matters such as the one-sided deal they are offering local people. 25. The planning system forces local people to deploy other technically recognised arguments as proxies for their genuine principled objections about unfairness. In most cases the planning arguments are valid and could apply equally to other developments including superstore developments, infrastructure projects or the building of logistics centres. However all of the latter bring local jobs or facilities that local people can use and personally benefit from. Only in the case of wind farms do the feelings of oppression and the resulting resentment create the motivation to make the planning system “work to rule”. 26. Repeated intervention by the Planning Inspectorate to enforce wind industry development has increased popular feelings of oppression and unfairness, thereby accelerating local, regional and increasingly national political resistance to wind energy development.

Recommendations 27. Implement a residential property compensation scheme similar to the Danish Promotion of Renewable Energy Act as soon as possible. 28. Focus future state efforts on promoting community ownership of wind energy developments, but prevent such schemes being used as a planning precedent for adjacent development that is not community owned. There will be very little take-up without this additional safeguard, given the climate of fear now prevailing in many rural areas. 29. Devise benefit systems that are proportional to the distance people live from the wind turbines, directly benefiting household economies. eg through mechanisms like a fixed percentage discount tariff for electricity during the life of the wind farm. 30. Remove the stewardship of the environmental protection standards relating to noise and shadow flicker from the Department for Energy & Climate Change. Transfer this key responsibility to another department or Energy and Climate Change Committee: Evidence Ev 25

agency that does not have conflicting responsibility for maximising the rate and scale of deployment for onshore wind turbines. June 2012

Written evidence submitted by the Montgomeryshire Local Council Forum (Local Councils in Welshpool, Llanfair Caerinion, Llandrino, Llandisillo, Llanfyllin, Kerry and Sarn) This submission is also supported by the North Wales Association of Town and Larger Community Councils and Welshpool Town Council

1.0 Introduction 1.1 This short submission is in response to Parliament’s request for evidence on the above by 5pm on 27 June 2012. 1.2 The Councillors discussed the request for evidence and this presentation at their meeting held on Wednesday 22 June 2012.

2.0 Cost of Producing Energy 2.1 The cost of producing energy shows that Gas and Nuclear are cheaper than On shore or Off shore wind farms. (see chart below) 2.2 The cost of On shore wind farms shown below do not count the cost of infrastructure to enable the transport to get to sites in remote areas such as Montgomeryshire. This is extensive in capital cost terms and also in environmental terms. 8.0

Standby 7.0 generation cost 6.0 Cost of 5.0 generating electricity 4.0

3.0

2.0

1.0

Cost of generating electricity of generating (p/kWh) Cost 0.0 Nuclear farm farm Coal-fired PF Coal-fired Coal-fired CFB Coal-fired Wave & Marine Wave Onshore Wind- Onshore Offshore Wind- Coal-fired IGCC Coal-fired Gas-fired OCGT Gas-filled CCGT Poultry-litter BFB Poultry-litter

3.0 Cost of Effects of Onshore Wind Farms 3.1 The cost to the communities in Montgomeryshire is: — The sheer scale of development proposed. — The size of the electricity hub (20 football pitches). — The 400kv pylon line needed to carry power to the grid. — The scale of transport to deliver components to the sites. 3.2 The cost to tourism and local business is an issue which needs to be assessed and support given to ensure that the effects of the Wind Farms does not leave a lasting legacy of creating poorer communities.

4.0 Transport Issues 4.1 The Montgomeryshire Wind Farms proposed total some 630 on 23 sites. 4.2 This generates 630,000 more vehicles on the rural roads and 7,500 abnormal load vehicles in 2,500 convoys over three–four years. 4.3 This is approx 14 convoys per week through the Mid Wales. 4.4 The industry and Welsh Assembly have accepted these figures are a good estimate. Ev 26 Energy and Climate Change Committee: Evidence

4.5 A full schedule showing how these figures are made up is available.

5.0 Survey 5.1 To gauge the feeling of residents in Welshpool a door to door survey was carried out with a leaflet dropped off one day (explaining it all and with some questions) and these were collected the following day. 5.2 There was a 45% return rate (5,579 forms issued with 2,484 returned) with the following key results: Against Onshore Wind Farms in Montgomeryshire 76.33% Concerned about the Hub 78.90% Concerned about the Pylon Line (400kv) 81.56% Concerned about the Transport 78.82% Seeking a public inquiry 68.68% 5.3 It is the sheer scale of what is an inefficient form of generating electricity that concerns the residents. 5.4 Without the enormous subsidy Wind Farm Companies would not be seeking to construct such sites.

6.0 How could Onshore Wind Farms be more acceptable? 6.1 Onshore Wind Farms in themselves are not an issue to everyone, indeed there is some support from the younger generation in Welshpool. 6.2 It is the environment effects with the substantial infrastructure which is causing the unrest. 6.3 Onshore Wind Farms would be more acceptable if the scale was reduced and the infrastructure reduced to a far more acceptable level. 6.4 The way forward for Montgomeryshire, and we suggest other areas, is for the Community and Town Councils be involved in a special conference/forum to find a solution. 6.4 Such an idea should be lead by the Town and Community Councils with advisors not lead by principle authorities.

7.0 Additional Comments 7.1 The Council feels much more action should be taken to substantially reduce energy thus reducing the need for such proposals as wind farms.

8.0 Oral Evidence 8.1 Welshpool Town Council confirms that it is prepared to give oral evidence with more details of the above if requested. June 2012

Written evidence submitted by Professor Gordon Hughes, Global Warming Policy Foundation (GWPF) 1. The economics of wind (and solar) power depend upon two critical features which determine the contribution which they make to meeting overall demand for electricity. The first feature is that wind power has very high capital costs and low operating costs per MWh of electricity generated. As such, it competes with electricity generated by nuclear or coal-fired generating plants (with or without carbon capture). The second feature is that the availability of wind power is both intermittent and random, so only a small portion of total wind capacity can be treated as being reliably available to meet peaks in electricity demand. 2. Neither of these features has a large impact on the operation of an electricity system when the level of installed wind capacity is less than 10% of peak demand, but they begin to impose increasingly heavy costs on system operation as the share of wind power in total system capacity approaches or exceeds the minimum level of demand during the year (base load). This threshold is due to be passed in the UK shortly after 2015. 3. When wind power is available, its low operating cost and market arrangements mean that it displaces other forms of generation. Market prices are lower, so that other generators require higher prices during periods of low wind availability to cover their operating and capital costs. It is expensive and inefficient to run large nuclear or coal plants to match fluctuations in demand or wind availability, so that their operating and maintenance costs will be higher. 4. At the same time, the risks of investing in new generating capacity will be increased by the impact of wind power on market prices, so that the cost of capital will be higher. Even if wind power was no more expensive per MWh than power from other sources its impact on other generators would still increase the aggregate cost of meeting the UK’s electricity demand, probably by a substantial margin. Energy and Climate Change Committee: Evidence Ev 27

5. One way of minimising the impact of wind power on other generators would be to impose a constraint on the amount of wind capacity that can be despatched at any time, so that, for example, no more than 20GW out of 36GW of installed capacity can be fed into the grid. Of course, that would be resisted by wind operators as it would reduce the already low load factor for wind farms. The guaranteed price per MWh would have to increase to attract the investment required to meet the Government’s targets for renewable generation in 2020, so that customers would have to foot even larger bills for wind power. 6. There is no escape from the consequences of the impact of wind power on other parts of the electricity system. In other areas of environmental policy this would be treated as a negative externality because the costs fall on electricity consumers as well non-wind generators. It follows that there is a prima facie case for taxing the source of the externality. Just as for fossil fuels, there would be strong arguments against the provision of subsidies designed to stimulate investment and output in wind generation. 7. A number of electricity markets outside Europe have developed arrangements to deal with intermittent or unreliable sources of generation, particularly hydro power. The most transparent approach is to require that there are long term contracts for the supply of reliable energy which in aggregate cover the predicted level of demand looking five or more years ahead. Hence, wind farms would have to either contract for storage and/or backup generation or absorb the cost of intermittency in some other way. Variants of this mechanism operate successfully in the US and Latin America (notably Brazil). They are more transparent and less likely to impose large costs on electricity customers than the hodge-podge of proposals for guaranteed prices (feed-in tariffs) and a capacity mechanism drafted by DECC. In addition, a proper market for long term reliable energy need not interfere with existing market arrangements designed to optimize generation and despatch on a half-hourly or daily basis, whereas it is inevitable that DECC’s proposals will compromise the efficient operation of such markets in the medium term. 8. Enthusiasts for wind power often suggest that the costs of intermittency can be reduced by (a) complementary investments in storage (pumped storage, compressed air, hydrogen, etc), and/or (b) long distance transmission to smooth out wind availability, and/or (c) transferring electricity demand from peak to off-peak periods by time of day pricing and related policies. However, if the economics of such options were genuinely attractive, they would already be adopted on a much larger scale today because similar incentives apply in any system with large amounts of either nuclear or run-of-river hydro power. 9. With sufficient commitment to research and development, some of these technologies may become economic within 20 or 30 years. However, up to 2030 and beyond it will remain much cheaper to transport and store natural gas, relying upon open cycle gas turbines to match supply and demand. As a consequence, any large scale investment in wind power up to 2020 will have to be backed up by investment in gas-fired open cycle plants. These are quite cheap to build but they operate at relatively low levels of thermal efficiency, so they emit considerably more CO2 per MWh of electricity than combined cycle gas plants. 10. The amount of investment in backup generation that will be required depends upon the minimum level of availability from wind farms spread over the UK. This is the amount of “reliable energy” offered by wind power. Calculations based on the geographical distribution of wind speeds have suggested that this might be as high as 25–30% of total wind capacity. Reality turns out to be rather different. In 2011–12 the minimum output from wind plants was less than 1% of actual installed capacity. This may rise as the share of offshore wind increases, but it would be unwise for any planner to rely upon this. For practical purposes, wind power in the UK must be discounted when considering the system requirement for reliable sources of generation. This means that all retirements of nuclear, coal or gas-fired plants plus any growth in peak electricity demand must be matched exactly by investment in new non-wind plants, most of which will be gas-fired capacity. 11. Meeting the UK Government’s target for renewable generation in 2020 will require total wind capacity of 36 GW backed up by 21GW of open cycle gas plants plus large complementary investments in transmission capacity. Allowing for the shorter life of wind turbines, the investment outlay for this Wind scenario will be about £124 billion. The same electricity demand could be met from 21.5GW of combined cycle gas plants with a capital cost of £13 billion—this is the Gas scenario. 12. Wind farms have relatively high operating and maintenance costs but they require no fuel. Overall, the net saving in fuel, operating and maintenance costs for the Wind scenario relative to the Gas scenario is less than £200 million per year, a very poor return on an additional investment of over £110 billion.

13. Further, there is a significant risk that annual CO2 emissions could be greater under the Wind scenario than the Gas scenario. The actual outcome will depend on how far wind power displaces gas generation used for either (a) base load demand, or (b) the middle of the daily demand curve, or (c) demand during peak hours of the day. Because of its intermittency, wind power combined with gas backup will certainly increase CO2 emissions when it displaces gas for base load demand, but it will reduce CO2 emissions when it displaces gas for peak load demand. The results can go either way for the middle of the demand curve according to the operating assumptions that are made.

14. Under the most favourable assumptions for wind power, the Wind scenario will reduce emissions of CO2 relative to the Gas scenario by 21 million metric tons in 2020–2.6% of the 1990 baseline at an average cost of about £415 per metric ton at 2009 prices. The average cost is far higher than the average price under the EU’s Emissions Trading Scheme or the floor carbon prices that have been proposed by the Department of Energy Ev 28 Energy and Climate Change Committee: Evidence

and Climate Change. If this is typical of the cost of reducing carbon emissions to meet the UK’s 2020 target, then the total cost of meeting the target would be £120 billion in 2020, or about 6.8% of projected GDP, far higher than the estimates that are usually given.

15. Wind power is an extraordinarily expensive and inefficient way of reducing CO2 emissions when compared with the option of investing in efficient and flexible gas combined cycle plants. Of course, this is not the way in which the case is usually presented. Instead, comparisons are made between wind power and old coal or gas-fired plants. Whatever happens, much of the coal capacity must be scrapped, while older gas plants will operate for fewer hours per year. It is not a matter of old vs new capacity. The correct comparison is between alternative ways of meeting the UK’s future demand for electricity for both base and peak load, allowing for the backup necessary to deal with the intermittency of wind power.

16. In summary, wind generation imposes heavy costs on other parts of the electricity system which are not borne by wind operators. This gives rise to hidden subsidies that must be passed on to electricity consumers. In the interest of both transparency and efficiency, wind operators should be required to bear the costs of transmission, storage and backup capacity needed to meet electricity demand. Only then will it be possible to get a true picture of the costs and benefits of relying on wind power rather than alternative ways of reducing CO2 emissions. June 2012

Supplementary written evidence submitted by Professor Gordon Hughes, GWPF

Measuring the Impact of Wind Power on System Costs

1. The debate on the economics of wind power is often accompanied by claims about the impact that reliance on wind power to meet targets for renewable energy will have on household energy bills in the UK. Many of these claims should come with a large health warning because they rely upon calculations that are incomplete or relate to something else altogether.

2. Official estimates of the impact on household bills refer to the joint effect of a whole slew of policies and initiatives. It is almost impossible to determine whether the claims are reliable, because the nature and coverage of the policies changes frequently and some elements are either subjective or rely upon assumptions with large margins of error. In any case, the issue is the impact of deploying wind power to generate a lot of electricity rather than some alternative source of generation. , Electricity Market Reform, etc are all irrelevant, because each initiative is distinct and can be evaluated on its own merits. The fact that investments in energy efficiency may reduce household bills is a reason for going ahead with that program, but it has no bearing on the economics of wind power.

3. Another feature of official and non-official estimates is that they are backward-looking. They compare the situation with the present fleet of generating plants if this were to continue in the future with system costs in which older, mostly coal, plants are replaced by wind generation. Again, this is irrelevant. A significant fraction of all generating capacity is due to be retired before 2020. So, the choice facing the UK is whether new investment to replace retired capacity and cater for demand growth should go to either (a) the lowest cost sources of generation—either gas CCGTs or nuclear plants (depending on discount rates and expected gas prices), or (b) wind or other renewable generating plants.

4. Since there is little likelihood of any nuclear plants being completed before 2020, my analysis has focused on gas CCGTs as the low cost baseline scenario. The crucial point is that the analysis focuses on the impact of new investment on the electricity system. Investors will not build gas CCGTs to run with a load factor of less than 20% to back up wind generation, unless they are paid to do so

5. A rather different defect is that academic estimates of the costs of investing in wind power often neglect the wider impact of wind power on the economics of system operation and investment decisions. The reason is that it is difficult to quantify such effects in a precise manner. Even so, for policy analysis it is much more important to be approximately right than precisely wrong.

6. It is generally agreed that the introduction of a large volume of wind capacity into the existing electricity market will change the distribution of market prices over the year and probably discourage investment in other types of generation such as gas or nuclear. Non-wind generators will have to cope with great market volatility and will apply a higher cost of capital to their investments. The same would be true of wind generators if there is a risk of significant curtailment in windy periods because must-run plus wind capacity exceeds base load demand, which will occur shortly after 2015.

7. The consequence is that an electricity market operating with a large share of wind capacity will require a higher cost of capital to compensate investors for the risks which they have to bear than one in which the share of wind is negligible. This will, of course, affect the cost of all capital-intensive forms of generation including nuclear, coal with CCS and solar power as well as wind power. Gas OCGTs and CCGTs have low capital costs and would not be affected to the same degree. Energy and Climate Change Committee: Evidence Ev 29

8. Of course, any reform that transfers market risks from producers to consumers will reduce the cost of capital and, thus, the cost of wind generation. The same is true for any profile of generation and is quite separate from the penalty attached to wind generation for a given market regime. Bringing back the CEGB in disguise may seem very attractive to those who advocate a centrally contracted market, but it should be remembered that there are large hidden costs associated with such arrangements. The move to liberalised and decentralised electricity markets around the world has brought large gains in the performance of electricity generators which should not be given up lightly. 9. There is another feature of some levelised cost models which can have an impact similar to an increase in the cost of capital. The basic issue is how to allow for changes in technical parameters such as the average load factor, thermal efficiency, outage rates and maintenance costs as generation plants get older. DECC’s levelised cost model incorporates an efficiency degradation factor which is applied selectively to fossil fuel plants in a manner that is not transparent and may not be plausible. 10. It is perfectly reasonable to assume that fuel and operating costs per MWh will increase for older plants while their load factors will be expected to decline. However, these changes will apply to all technologies, not just gas and coal-fired plants. Also, the date at which performance begins to tail off—and at what rates—is very important. Such details are rarely documented properly, even though they can have a significant impact on the results of levelised cost comparisons—as much as £10 per MWh. 11. Levelised cost calculations are inherently artificial. The perspective of investors and operators is rather different and this is what should underpin policy evaluations. Most operators would expect to follow a maintenance regime designed to ensure that a new plant will perform in accordance with its design specification for a period of 15–25 years depending upon the technology and expected plant life. After 60–65% of the expected plant life performance may start to degrade, even with good maintenance, and the operator will consider whether to carry out a major rehabilitation or life extension to reverse the impact of performance degradation. In effect there is a choice between (a) responding to a higher level of operating costs by reducing the load factor and running the plant when market prices are relatively high, or (b) making a significant investment to postpone performance degradation and continuing to run the plant with a relatively high load factor. 12. In technical terms an investment in a new power plant should be viewed as offering a combination of (i) a (relatively) reliable flow of electricity for sale over an initial period of 15–25 years, plus (ii) a real option offered by the opportunity either to invest in rehabilitation or to operate the plant as peaking or mid-merit capacity for an additional 10–20 years. Assessing the residual (real option) value of the plant after the initial period is technically difficult and involves a variety of assumptions about probabilities and market conditions many years in the future. Few investors are inclined to do this, so the usual approach is to assign a conventional residual value to the power plant at the end of the initial period. The estimates reported below are based on a rather generous assumption that power plants are given a residual value of 20% of their original capital cost (in real terms) after an initial operating period of 60% of their maximum operating life. This provides the basis for using a simple annuity calculation to estimate the capital charge for a new power plant.

The Extra Cost of Wind Generation 13. Table 1 shows the total system costs in 2020 of the baseline Gas scenario and three alternative versions of the Wind scenario. The capacity of wind farms in each of the Wind scenarios is normalised so that total wind output in 2020 is 94.4TWh as explained in Section 7 of Why is wind power so expensive? The differences between the wind scenarios concern the degree to which future wind plants are located onshore or offshore. (a) Mixed—this is the main Wind scenario in which onshore wind capacity in 2020 is 12GW while offshore capacity is 24GW. This scenario corresponds to the likely outcome if most of the onshore wind farms that have planning permission go ahead, while the focus of future development shifts offshore. (b) More onshore—this scenario assumes twice the amount of onshore wind capacity in 2020 as under the Mixed scenario—a total of 24GW. Because of the lower load factor for onshore wind farms the total amount of wind capacity in 2020 to meet the output target would have to be about 39GW. Given public opposition to the development of onshore wind farms and constraints on the availability of suitable sites this scenario is likely at or above the maximum amount of onshore wind capacity that could be achieved by 2020. (c) Future offshore—this scenario examines the impact of cutting subsidies for onshore wind generation through the ROC regime substantially so that there is almost no further development of onshore wind farms.

The system costs include the cost of backup generation, transmission and a CO2 floor price of £30 per tonne of CO2. 14. The pre-tax real cost of capital or hurdle rate of return, which is what determines the costs borne by consumers, for power projects is determined primarily by two sources of risk: (i) development risk associated with delays and cost overruns during project development, and (ii) market and operational risk after construction. Most analyses show that development risks have a large impact on the cost of capital and are Ev 30 Energy and Climate Change Committee: Evidence

considerably higher for wind power projects than for gas-fired power plants. Post-construction risks will be large for intermittent sources of generation and peaking or backup plants, because they are more exposed to volatility in market prices. Hence, the cost of capital for the wind scenarios will be considerably higher than for the gas scenario. Table 1 COMPARISONS OF SYSTEM COSTS BY SCENARIO (£ BILLION PER YEAR AT 2010 PRICES INCLUDING CO2 TAX) Real cost of Gas Wind scenario capital scenario Mixed More Future Onshore Offshore 8% 8.1 15.4 14.0 15.8 9% 8.2 16.2 14.7 16.6 10% 8.3 16.9 15.5 17.5 11% 8.5 17.8 16.2 18.3 12% 8.6 18.6 17.0 19.1 Total wind capacity in 2020 (GW) Onshore 12 24 8 Offshore 24 15.25 27 Source: Author’s calculations 15. Standard estimates of the real cost of capital for fossil-fuel generators under current market conditions tend to fall in the range 7–9%. The cost of capital for wind projects which rely on ROC subsidies is rather higher with a typical range of 9–12% with values for offshore wind at least 2% higher than the equivalent cost of capital for onshore wind. The ranges given below for the additional system costs associated with wind power are based on the assumption that the real cost of capital for the Gas scenario as the baseline is 8%, while the average real cost of capital for wind generation in the Wind scenarios is a minimum of 10% and a maximum of 12%. 16. Hence, the additional system cost for the Mixed Wind scenario is a minimum of £8.8 billion per year (= £16.9 billion for Mixed Wind @ 10% cost of capital—£8.1 billion for Gas @ 8% cost of capital) and a maximum of £10.5 billion per year (= £18.6 billion for Mixed Wind @ 12% cost of capital—£8.1 billion for Gas @ 8% cost of capital). The differences in system costs would be rather lower for More Onshore wind scenario with a range of £7.4–8.1 billion per year, while the range would be £10.2–11.0 billion per year for the Future Offshore wind scenario in which all future wind farms are located offshore. Note also that total system costs would be much higher under the Mixed Wind scenario than under the Gas even if an identical cost of capital is used for all types of generation. The difference varies from £7.3 billion per year with a real cost of capital of 8% up to £10 billion per year with a real cost of capital of 12%. 17. For the main Mixed Wind scenario the additional system costs are equivalent to £90–110 per MWh of wind generation. Under the other wind scenarios the additional system costs vary from £78 per MWh for the More Onshore scenario to £117 per MWh for the Future Offshore scenario. As a reference point, the average cost of new generation under the Gas scenario is £72 per MWh for the middle of the cost of capital range. Clearly, the increase in system costs due to the introduction of substantial amounts of wind power is substantial, varying from 110% to 160% of costs under the baseline scenario. 18. Another point to note is that the system costs for the Gas scenario include about £1.1 billion per year of CO2 floor price payments in 2020, whereas the equivalent figure for the Wind scenarios is £0.3 billion per year. Since the government can readily ensure that such payments accrue to the Exchequer, this means that other taxes can be lower while maintaining the same level of total tax revenue. This effect may be partly offset by higher corporation tax payments on profits accruing to wind generators under the Wind scenarios, but this is much more uncertain because it depends upon capital allowances, financial structures and other factors. With typical gearing ratios (ie the proportion of total capital costs financed by debt) of 60–80% the additional corporation tax revenue is unlikely to be more than £0.6 billion per year in 2020 and may be considerably lower.

Translating System Costs to Household Bills 19. It is complicated to assess how any increase in the average cost of electricity generation will affect household electricity bills. Most of the calculations that gain widespread currency are misleading because they are incomplete. There are two critical issues that have to be considered: (a) What will be the incidence on household and non-residential consumers? Industrial and large business customers are generally more sensitive to electricity prices than households. That is reinforced by the fact that the impact of wind generation on wholesale prices will be larger than the impact on retail prices, which include a larger element of distribution and retail costs. Under standard models of tax incidence, which apply in this case, the burden of higher system costs will not fall uniformly on all consumers. One mechanism by which this will happen is Energy and Climate Change Committee: Evidence Ev 31

that any decline in industrial demand will fall disproportionately on base load demand and, thus, increase the differential between base load and daytime prices. Through such adjustments the average wholesale price paid by households—and probably small business customers—will increase by more than the average price paid by industrial and large business customers. The effect is likely to be even greater if either time of day or marginal cost pricing are adopted on a significant scale. (b) What will be the impact on network costs and retail margins? Both will be affected by an increase in the average wholesale price of electricity. Transmission and distribution losses are equivalent to 7–8% of the total amount of electricity that is transferred over the network. The largest portion of these losses are “technical losses” due to heat and other losses in cables, transformers and other network equipment, while the remainder are “non-technical losses” due errors or mismatches in metering and billing. In principle, the level of technical losses will vary with the network load, but trying to identify how this might change in future is not practical. The costs of losses are borne by network operators and passed on to customers. Hence, a total increase in generation system costs of £8.8 billion will translate to a cost to all customers of £9.5 billion. On top of this it is also necessary to take account of an increase in retail margins. A part of this will be due to the commercial losses experienced by energy suppliers, but the largest component will be linked to the cost of hedging whose cost will increase substantially. The higher level of wholesale price volatility caused by wind power will have a direct effect on hedging costs which will be amplified by the indirect effect on the cost of capital employed in the supply business.

20. Households account for 36% of final electricity consumption after deducting losses and internal use for electricity generation and in the energy sector. Given the factors outlined above it is reasonable to assume that at least 40% of the total increase in system costs will fall on household customers with a high estimate of 50%. Similarly, the increase in market volatility is assumed to increase the supply markup on wholesale prices (including environmental costs and levies) from 28% in 2010 to 30–33% in 2020.

21. On this basis the average household electricity bill would increase from £528 per year at 2010 prices to a range from £730 to £840 in 2020 under the Mixed Wind scenario. These figures amount to increases of 38% to 58% in the average household bill relative to the baseline under the Gas scenario. The equivalent ranges for the other scenarios are 29–46% for the More Onshore Wind scenario and 40–62% for the Future Offshore Wind scenario.

APPENDIX A

ALTERNATIVE ASSUMPTIONS

A1. The results reported above are based on assumptions that are rather favourable to wind power. The penalty associated with the Wind scenario would increase if less favourable assumption are made: (a) Economic life. The analysis assumes that capital costs of wind plants are recovered uniformly over an economic life of 25 years. Experience shows that wind operators will expect to recover their costs over 15 years or less, since both downtime and maintenance costs rise sharply after 15 years. Some wind turbines have a life of less than 10 years. If the expected life of wind turbines is reduced by five years to 20 years, then the addition system cost for the Mixed Wind scenario would increase by £1.0 billion per year. (b) Load factors. The load factors for onshore and offshore wind are based on current experience. In practice, the load factor for new onshore plants will fall as they are likely to be located in places with less favourable wind profiles. For example, the average load factor for onshore plants in both Denmark and Germany with much larger wind capacities relative to total capacities is well below 20%. The prospect of significant wind curtailment after 2020 would further reduce the expected load factor. If the actual load factors for onshore and offshore wind were 20% and 28% respectively, which is consistent with their performance in Denmark, then the additional system cost for the Mixed Wind scenario would increase by £1.6 billion per year. (c) OCGT performance. The cost of operating gas turbines as backup is based on an estimate of thermal efficiency which can be achieved if plants are just switched on and off when extra capacity is required. In practice, the plants will not operate in this way. The volatility of wind generation from minute to minute or one 5 minute period to the next means that there is a significant requirement for spinning reserve, ie capacity that is running but which is not contributing power to the system. If this reserve is provided by OCGTs, their effective thermal efficiency will be lower than the theoretical figure. Alternatively, and perhaps more likely, existing coal plants or CCGTs will be used as spinning reserve, in which case there will be fuel consumption and CO2 emissions in the rest of the system that should be taken into account. If the actual thermal efficiency of OCGTs was 30% rather than the figure of 35% assumed in the main analysis, the additional system cost for the Mixed Wind scenario would increase by £0.3 billion per year. Ev 32 Energy and Climate Change Committee: Evidence

A2. Adopting realistic but less favourable assumptions for these three sets of parameters increases the range of additional system costs for the Mixed Wind scenario from the range £8.8–10.5 billion reported in the text to £12.0–13.6 billion. The corresponding range for the impact on average household electricity bills would be from £275 to £400 per year. A3. One of the major uncertainties about any projections of future system costs concerns the path of future gas prices. Most official estimates of the costs and benefits of wind power rely heavily upon a rather pessimistic forecast that gas prices will continue to increase as they have over the last five–10 years. This is justified by reference to the supposed link to world oil prices. The factual and analytical basis for such forecasts is largely wrong, unless the UK were to pursue deliberately wrong-headed policies. A4. Analysts hold very different views about the likelihood and/or desirability of large scale exploitation of unconventional gas in the UK—not just shale gas but also coal bed methane. The summary which follows does not rely upon any assumptions about the scale of such production. Nonetheless, the lesson from recent discoveries of both conventional and unconventional gas is that gas is an extremely abundant fuel on a global scale. In the medium and longer term the cost of gas in the international market is not driven by scarcity but by the costs of investing in the infrastructure required to extract and transport it. Shale gas has driven down the market price of gas in the US because the marginal cost of extraction is low and there is a large amount of pipeline capacity to transport the gas. A5. There is no reason why gas prices in the UK should track global oil prices. The fact that this has happened in the recent past is a consequence of poorly designed contracts signed by Germany and other European countries for essentially political reasons. The same is true for the prices paid by countries such as Japan and Korea. Certainly, gas prices may rise in line with oil prices in future but the reason will be government failure not the logic of the international gas market. With an appropriate regime to produce and store gas—UK gas storage is woefully small—the market price of gas will be linked to the cost of building infrastructure to extract and transport gas. Despite the inevitable problems with large projects this is falling in real terms over time and will continue to do so as large new discoveries of gas come on-stream. A6. If the levelised average gas price used in the calculation is 10% lower than the assumed value of £7.40 per GJ, then the additional system cost under the Mixed Wind scenario increases by about £0.4 billion per year. Because CCGTs are so much cheaper to install and operate than wind turbines, the expected future price of gas is much less important than the expected load factors for onshore and offshore wind turbines in assessing the additional system costs of relying upon wind power rather than gas. Focusing on energy security and independence from international energy prices makes little sense if the alternatives are very costly.

APPENDIX B A NON-TECHNICAL OVERVIEW OF GENERATION TECHNOLOGIES B1. Many non-specialists find the combination of acronyms and technical terms that is characteristic of many discussions of power generation confusing and difficult to grasp. Even consulting entries in Wikipedia may not provide much illumination since they are often written for people with a reasonable technical background. Hence, this appendix has been written for non-specialist readers who wish to understand the key concepts of the different technologies that are discussed in the debate about wind power. Specialist readers may consider that it relies upon gross over-simplification but that is an inevitable cost of providing a concise overview for a non-specialist audience. B2. Most forms of electricity generation on a large scale (other than solar photo-voltaics) involve the conversion of energy into rotational force that drives an alternator in which a rotating magnetic field induces an alternating electric current in a stationary set of conductors that surround it. The number of magnets in the magnetic core and its speed of rotation determine the frequency of the alternating current (50 Hz in Europe, 60 Hz in North America). The voltage of the AC current that is produced by the generator is “stepped up” to match the voltage of the transmission grid and then “stepped down” for distribution to users connected to the electricity network. B3. Wind turbines are very simple machines that are familiar to almost everyone. The flow of air over the blades of the turbine causes them to rotate. This mechanical energy is converted to electricity through a combination of gears and an electricity generator. While the blades, the rotor shaft and the supporting tower are the most visible components of a wind turbine, they account for only about 35–40% of the total cost. Other components include the civil works required for installation, gears, electrical generator, transformer, etc. The amount of electricity produced by a wind turbine depends strongly upon the wind speed since the potential wind energy available varies with the cube of wind speed. Modern wind turbines have an output profile that is zero below a cut-in speed of three–four metres per second (m/s) and reaches their maximum output in the range 12–15m/s. For safety reasons there is a cut-out speed—usually 25m/s—above which the turbine has be closed down. [1m/s converts to 2.24mph, so the operating range of a modern wind turbine is approximately 8 to 56mph, while rated output is only achieved for wind speeds greater than 27mph or at least Force 6 (strong breeze) on the Beaufort Scale.] B4. There are fundamentally two different ways of generating electricity from fossil fuels. The traditional way is to burn the fuel in a boiler which produces steam and then the steam is directed into a turbine whose Energy and Climate Change Committee: Evidence Ev 33

rotation is used to generate electricity. Almost all coal and oil plants operate in this way, as do an older generation of gas plants. The thermal efficiency (ie the proportion of the energy content of the fuel that is converted into electricity) of such plants is limited by the engineering and thermal problems of converting fuel into steam and then steam into electricity. Even the most modern steam plants do not achieve a thermal efficiency of much more than 42%.

B5. The alternative is represented by a jet engine, which is technically a gas turbine. The fuel is burned in a compressed stream of air so that the resulting explosion expands the air and thereby drives a turbine directly. Most people are familiar with jet engines. What are called open or single cycle gas turbines (OCGTs) are often derivatives of jet engines with the turbines designed to power an electricity generator rather than provide backward thrust. On their own, gas turbines are less efficient than steam turbines in generating electricity but they are compact and flexible because they can start and stop quickly. Typically their thermal efficiency is 30–35% depending on how they are operated, though some new gas turbines are reported to achieve an efficiency of 38–40% when running at a steady rate.

B6. A combined cycle gas turbine (CCGT) literally combines the two technologies. The first stage consists of one or more gas turbines. Then, the hot gases from the first stage are used to produce steam which drives a second stage steam turbine. The combination of the two stages provides considerable flexibility because plants can be designed with the option of running the first stage only. While natural gas is the fuel of choice for CCGTs, they can run on most types of gas-oil such as kerosene, jet fuel or diesel.

B7. There are also a small number of coal-fired plants around the world which have an initial stage of coal gasification with the gas being used to feed the equivalent of a CCGT. Plants based on this technology, known as integrated gasification combined cycle (IGCC), are expensive to build and complex to operate, but they can achieve relatively high levels of thermal efficiency (about 50%) and they can be attractive where coal is cheap and environmental controls are strict.

B8. The thermal efficiency of CCGTs has steadily improved (along with the performance of jet engines) as designers have found ways of making each stage more efficient. When CCGTs were first introduced in the 1980s their typical thermal efficiency was less than 50%—the typical design level was 48% but achieved values were closer to 45%. Today the design specification of a modern CCGT will often be 60% or even higher and the achieved values will be about 58%. As a consequence, gas-fired CCGTs have overtaken coal-fired plants as the dominant technology for new fossil fuel plants providing that a reliable supply of gas is available. A further advantage is that the average capital cost of CCGTs per MW of capacity is much lower than for steam turbines and they can be constructed much more quickly—typically two–three years by comparison with four–five years for coal-fired plants.

B9. An alternative way of combining electricity generation with heat recovery is offered by combined heat and power (CHP) plants. Any steam or gas turbine can be converted to CHP operation by using the waste heat from the steam or gas turbine to heat water that can be used for industrial processes or residential use. In principle, the most efficient form of CHP is offered by tri-cycle operation which combines a CCGT with a final stage of heat recovery to produce hot water. The thermal efficiency of such plants can exceed 80%. However, the high efficiency of CHP plants involves a significant loss of flexibility and requires large complementary investments to distribute hot water. Heat losses, even from insulated pipes, mean that it is rarely sensible to transport hot water over a distance of more than 10–20km. For a temperate country such as the UK, unless circumstances are particularly favourable, it is usually more efficient to transport gas which can be burned to produce hot water in high efficiency boilers in situ than to invest in the distribution of hot water from centralised heating or CHP boilers.

B10. Maintenance costs for all gas or steam turbines are strongly linked to the number of start and stop cycles they experience (because the thermal stresses are greatest during cycling up or down). Because of their origin as jet engines, OCGTs are designed to start and stop quickly as well as to lower the maintenance cost of each cycle. That is why they are better suited to back up wind turbines than are conventional steam plants. In running electricity systems for which demand may vary a lot from one five or 30 min period to the next, the disadvantage of the low thermal efficiency of OCGTs is offset by their flexibility and responsiveness. On the other hand, it is not economic to run them continuously because their fuel cost per unit of electricity is too high. July 2012 Ev 34 Energy and Climate Change Committee: Evidence

Further supplementary written evidence submitted by Gordon Hughes, Global Warming Policy Foundation

Robert Gross and a group of colleagues at Imperial College have submitted Supplementary Evidence to the House of Commons Select Committee on Energy and Climate Change that comments on the evidence which I prepared for the Committee on behalf of the Global Warming Policy Foundation. Since it took them about three months to prepare their comments, it is not possible to prepare a full rebuttal at short notice; I will do this in due course. Nonetheless, their arguments illustrate important features of the UK government’s approach to policy analysis in the energy sector which should be highlighted.

A key problem is a recurring confusion between predictions (what will be), plans (what should be) and policy scenarios (what would have to be). The Imperial College group assert that I have overstated the amount of wind capacity in 2020 and, thus, that my estimates of the costs of current policies are too high. In doing so, they are not comparing like with like. They rely upon a comparison between a set of predictions (which change regularly) and my policy scenarios, which spell out what would be required to meet the UK government’s targets for renewable energy. The UK has a very poor record in energy forecasting over the last 30–40 years, so any evaluation of policy should be based upon something more solid than the most recent set of predictions.

Perhaps official predictions are supposed to reflect a firm plan for 2020. In that case the policy analyst has to ask whether the critical assumptions built into the plan are well founded and how the plan is to be achieved. An endemic problem for policy formulation in the UK as well as planning around the world is the tendency to over-optimism, to assess what one wants to happen rather than what realism and evidence suggests will happen. The outsider has to ask: what steps have been taken to minimise the risks and consequences of over-optimism?

The Imperial College group rely heavily upon claims based upon their models of wind output, dispatch, etc. Such models can be instructive but they do not provide concrete evidence, especially as their models explicitly exclude consideration of the stochastic nature of wind power. My approach is different. I have based my policy scenarios on data relating to the operation of the electricity system over the last four years (and rather longer for wind farms). I am unwilling to assume that key variables such as load factors, the pattern of wind availability and its correlations with demand, etc are going to be substantially different from what has been the case in the past.

Similarly, the Imperial College group appear to miss the point of my argument that the reductions in carbon emissions may be much smaller than conventional claims suggest. My examples are deliberately simplified to illustrate the point that the net outcome will depend upon adjustments in the whole electricity system, which— in turn—will be affected by future investment decisions. This has nothing to do with the efficient use of existing capacity, but future investment will depend upon how that capacity is used. It seems that both the Imperial College group and DECC assume there will be large investments in CCGTs in the middle or later parts of the current decade to replace plant which will be restricted or retired as a consequence of the EU’s recent Industrial Emissions Directive. The difficulty is that the load factors for the new plants may be very low if the predictions of wind penetration are realised. In equivalent situations elsewhere the response has been to invest in single cycle plants or to run older plants in single cycle mode. This is not a nonsense scenario but a reflection what actually happens.

The story of wind power in Europe is one of consistent over-optimism about performance and costs reinforced by an apparent unwillingness to define clear policy options and then construct analyses based on concrete evidence. Modelling is not a substitute for evidence. In practice, the Imperial College/DECC claims about the costs of current policies rest upon the old story of “this time everything is going to be different”. Really? How could we test this?

I would propose a simple market test that bears directly on the subject of the original ECC hearing. If the proponents of the Imperial College/DECC view of this issue believe that my calculations of the costs of existing policies are wrong, why do they not endorse a major and continuing reduction in the level of subsidies? For example, the costs claimed would be consistent with a reduction to 0.5 ROCs per MWh immediately and to zero by 2020 for onshore wind and something equivalent for offshore wind.

The current and proposed systems of subsidies for renewable energy are equivalent to a major programme of taxation and public expenditure with a probable cost that will run into the billions or even tens of billions of pounds per year over the next decade. It is incumbent on those who wish to retain these subsidies to demonstrate that taxpayers are receiving good value for their money. I have profound doubts that current and/ or proposed policies meet that criterion. Clearly, the Imperial College group believe otherwise, but they have produced no evidence to support their view. No one doubts that we can live with an electricity system including large amounts of wind power. The question is whether the public is willing to bear the full cost when this is fully transparent. At the moment, the costs are neither properly assessed nor are they transparent. October 2012 Energy and Climate Change Committee: Evidence Ev 35

Written evidence submitted by the Grantham Research Institute on Climate Change and the Environment, London School of Economics 1. What do cost benefit analyses tell us about onshore and offshore wind compared with other measures to cut carbon? 1.1 Onshore wind has the lowest cost of all forms of low-carbon electricity generation. It is also competitive (or will soon be competitive) with fossil fuel-based power, once the economic costs of carbon are fully factored in. Offshore wind, in contrast is still a relatively expensive technology. 1.2 However, the visual impact of onshore wind is a non-trivial local issue and should be built into cost calculations. First, onshore wind developments should not be allowed in areas of outstanding natural value. Second, people value natural landscapes and are willing to pay to preserve them. Studies indicate that willingness to pay could range from 0.3 to 4p/kWh. This would add between 3 and 60% to the current levelised cost of onshore wind (which is 6.6 to 9.3p/kWh). Such local environmental constraints can make more expensive renewable technologies—such as offshore wind or solar photovoltaics—potentially attractive. One can think of their extra cost as the premium society is willing to pay to avoid the local environmental cost of onshore wind. 1.3 There is a distributional aspect to wind developments in that those bearing the local environmental cost (local communities) are different from the beneficiaries of a project (electricity consumers and producers). In addition to concern about costs and benefits, there are therefore questions of adequate benefit sharing with (or financial compensation for) local communities.

2. What do the latest assessments tell us about the costs of generating electricity from wind power compared to other methods of generating electricity? 2.1 The UK is bound, under the Climate Change Act (2008) and the subsequent carbon budgets, to cut its annual greenhouse gas emissions by half by 2025, compared with 1990. This requires a power sector that is virtually carbon-free by the mid to late 2020s. With this in mind, the issue of wind energy deployment becomes a choice between this and other low-carbon energy sources, not between wind energy and fossil fuels. 2.2 It has been argued that efficient combined cycle gas turbine (CCGT) power plants may be a cheaper way of meeting our 2020 targets. However, the further decarbonisation required in the 20s cannot be achieved by relying heavily on unabated gas power stations. Prioritising penetration of CCGT plants rather than wind energy risks higher costs in the long run as undesirable technologies are locked in that would then have to be scrapped prematurely.

3. How much support does wind power receive compared with other forms of renewable energy? 3.1 Renewable energy subsidies can help overcome the market failure related to introducing relatively immature technologies to the market. These market failures mean that new low-carbon technologies will not develop at all or quickly enough if the market forces alone are relied on, for instance because of the so-called “valley of death” between the push of publicly-funded research and the pull of commercial development. Renewable energy subsidies complement (and, where the carbon price is too low, partly replace) policies to put a price on carbon. Carbon must be priced to reflect the environmental cost of climate change and remove the implicit subsidy fossil fuels enjoy for their greenhouse gas pollution. 3.2 Renewables subsidies should be gradually reduced and removed as technologies mature and overcome the market failures. For onshore (but not offshore) wind we can expect this process to be relatively quick. For example, some estimated that onshore wind could be economically competitive with older conventional sources of energy in five–10 years (see eg Bloomberg NEF, 2011). It is important that the phasing-out of subsidies is done in a predictable way, with the criteria and timetable for decisions being clear and transparent. Ad-hoc and sudden changes in subsidy levels creates policy risks which act as a disincentive to private investors and increase energy costs. 3.3 It is worth noting that fossil fuels also benefit from a range of direct and indirect subsidies. Subsidies for fossil fuels are mostly direct consumption subsidies through the lower rate of VAT on domestic electricity (although this may also benefit non-fossil-fuel electricity) and other tax rebates. The OECD (2011) estimates that subsidies for coal, gas and petrol in the UK were in the order of £3.6 billion in 2010. Furthermore, fossil fuels benefit from direct exploration and production subsidies, such as the £65 million support for the development of fields west of the Shetlands announced by the Chancellor in the last Budget (HM Treasury, 2012).

4. Is it possible to estimate how much consumers pay towards supporting wind power in the UK? (ie separating out from other renewables) 4.1 The impact of renewables is embedded in the cost of the Renewables Obligation, the main subsidy mechanism for renewable energy. Using official estimates of future electricity consumption and generation capacity (DECC, 2011; CCC, 2011; ENSG, 2012), and assuming an average Renewable Obligation Certificate (ROC) price of £45 per MWh, it is possible to obtain an indicative value for the contribution of wind Ev 36 Energy and Climate Change Committee: Evidence

technologies to the overall bill. This would be about 0.18p/kWh in 2011 and 0.37p/kWh in 2020 for onshore wind, and about 0.29p/kWh in 2011 and 1.47p/kWh for offshore wind. Assuming the average household consumption of electricity will remain unchanged at 3,400kWh per year,1 this would imply an additional annual cost of £6 in 2010 and £13 in 2020 for onshore wind, and roughly £10 in 2010 up to £50 in 2020 for offshore wind.

5. What lessons can be learned from other countries? 5.1 Experience from Germany and Denmark, which have wind capacities respectively of 27,000 MW and 3,700 MW), confirms that the involvement of local communities is crucial when developing new installations. Unlike the UK, where the majority of onshore wind projects are developed and owned by commercial companies, the majority of projects in Germany and Denmark (up to 80% in Denmark) are characterised by a “community ownership” model, where local communities pool resources to finance the purchasing, installation and maintenance of projects, and individuals are entitled to a share of the annual revenue which is proportional to their investment (CCC, 2011).

6. What methods could be used to make onshore wind more acceptable to communities that host them? 6.1 A study by Bowyer at al. (2009) investigating UK, Danish and German experiences confirms that to create an effective planning system that respects concerns about nature conservation whilst securing rapid onshore wind development, a number of requirements must be met. These include: early engagement of stakeholders, clarity over nature conservation concerns and high quality environmental impact assessments. It is advisable that such elements are taken into account in the context of the UK planning framework. 6.2 In turn, wind investors will want to see wind developments to be regulated by sound policy-making. As outlined by Bassi et al. (2012) key measures should include: a clear price on carbon; a planning system that (i) reduces the costs for developers, (ii) factors in local environmental concerns and prevents developments in important environmental areas and (iii) ensures appropriate compensation in areas where local impacts are acceptable; and flanking measures eg better interconnectivity of grids, are required to ensure that the electricity system can cope with intermittent resources. June 2012

Supplementary written evidence submitted by Grantham Research Institute on Climate Change and the Environment The Rationale for Subsidies to Renewable Energy in a Carbon Constrained World Corrective subsidies are justified in situations where the market does not provide the socially desirable outcome, ie where there are market failures. The main market failure in the case of energy is that the market does not incorporate the environmental cost of climate change in the price of goods and energy. This means fossil fuels are implicitly subsidised for their greenhouse gas pollution, and therefore do not compete on equal ground with low carbon technologies. This market failure can be directly addressed by attributing a price to carbon emissions. The EU Emissions Trading Scheme does this for about 40% of the UK’s greenhouse gas emissions. However, the current carbon price set by the EU ETS has not been stable, certain or high enough to encourage sufficient low-carbon investment in the UK (Her Majesty’s Government, 2011). The UK government therefore decided to introduce a carbon price floor to encourage additional investment in low-carbon power generation, by providing greater support and certainty to the carbon price. This will be introduced in April 2013 at around £16/tCO2, and will gradually increase to reach £30/tCO2 in 2020 and £70/tCO2 in 2030 (both in 2009 prices) (Her Majesty’s Treasury, 2011). There are additional market failures in the case of renewable energy that justify additional intervention. They have to do with the speed at which innovative new technologies are being adopted by the market. New technologies like renewables can be stalled by the so-called “valley of death” that exists between research and development in the laboratory and widespread commercial deployment in the field. It is often a very expensive and lengthy process to find the cheapest way of manufacturing new products on a large scale. Overcoming these barriers and accelerating the deployment of renewable energy sources is the purpose of the Renewable Energy Obligation. By improving technology through learning-by-doing and economies of scale, this subsidy helps to reduce the cost of renewable energy technologies through time. It also ensures that the UK will meet its European Union commitment of meeting 15% of the annual consumption of energy from renewable sources by 2020. It is worth noting that fossil fuels also benefit from a range of support measures—mostly direct consumption subsidies through a lower rate of VAT on domestic electricity (although this may also benefit non-fossil-fuel electricity) and other tax rebates. The OECD (2011) estimates that subsidies for coal, gas and petrol in the UK were in the order of £3.6 billion in 2010. Furthermore, fossil fuels benefit from direct exploration and 1 The Department of Energy and Climate Change uses instead a higher estimate of 4,000 kWh. For consistency we adopt here an assumption based on the Committee on Climate Change. This is also more consistent with Ofgem’s estimates—see footnote 16. Energy and Climate Change Committee: Evidence Ev 37

production subsidies, such as the £65 million support for the development of fields west of the Shetlands announced by the Chancellor in the last Budget (HM Treasury, 2012). Renewable energy sources may therefore require a certain amount of support to compete on equal ground with subsidised fossil fuels.

The UK Renewable Obligation In the UK the main subsidy to renewable energy sources, since 2002, has been the Renewables Obligation. This requires electricity end-suppliers to purchase a given fraction of their annual electricity supply from producers using specific renewable technologies, obtaining in exchange a certain amount of Renewable Obligation Certificates (ROCs). Currently, for each MWh generated, onshore wind installations receive 1ROC, offshore wind installations 2ROCs, and other renewable technologies between 0.25 to 2ROCs. Where end- suppliers do not obtain a sufficient amount of ROCs, they can either purchase them on the market at a variable price, or pay a penalty (known as the buy-out price), which is currently around £40 per ROC. From 2014 the ROCS will be replaced by new long-term contracts (Feed-in Tariffs with Contracts for Difference), which will run in parallel with the Renewables Obligation to 2017 (Her Majesty’s Government, 2011). By increasing the profitability of the renewable projects in the pipeline, the subsidies allow some of the installations, that would not otherwise be competitive, to be built, increasing the overall installed capacity of renewable energy sources and accelerating the commercial break-through of the technology through economies of scale. Estimating the cut-off point between profitable and non profitable projects is not a straightforward exercise, as several pieces of information regarding cost and revenues are retained by the industry, rather than the regulator. This generates a problem of asymmetric information. It is advisable that, in the future, it should be made mandatory for generators to disclose some information in exchange for the subsidies, in order to for the regulator to better estimate the level of support required.

The Impact of Renewable Subsidies in the UK and in Other EU Member States The ROC mechanism increases electricity prices, which in turn are passed on to consumers’ bills.Inan average electricity bill of a UK average household, which in 2011 was about £600 (14.9p/kWh), the Renewable Obligation is estimated to account for £17 (0.5p/kWh). This is expected to increase to £48 (1.1p/kWh) in 2020 (DECC, 2011a).The specific support to onshore wind through the ROCs is estimated to be around £6 in 2011 (0.2p/kWh) and £13 in 2020 (0.4 p/kWh) (Bassi et al, 2012). Similar mechanisms are in place in other EU Member States. We highlight here some examples from Germany and Denmark. A comparison of costs per kWh is shown in Table 1 below. In Germany the Renewable Energy Sources Act (EEG) requires grid operators to give priority electricity generated from renewable energy sources, paying the relevant statutory minimum rates to the plant operators. These costs are also passed onto electricity users. In the electricity bill of a German average household of €792 (£706, ie 20.2p/Kwh)2 in 2009, around €37 (£33, ie 0.9p/kWh) were attributed to the EGG measure (BMU, 2009). In Denmark since the 70s wind turbine owners are paid a supplement to the electricity production price, through fixed feed-in tariffs. Tariffs are set in the Danish Promotion of Renewable Energy Act, and depend on the turbine size and the year when they were connected to the grid. New onshore and offshore turbines connected after 2008 receive DKK 0.25/kWh (about 28 p/kWh)3 for the first full-load hours, then they receive the market price. In addition, DKK 0.23/kWh (26 p/kWh) is paid to cover balancing costs for the full lifetime of the turbine. The supplement to the market price is recouped as a Public Service Obligation (PSO) in the electricity bills. In 2011 the PSO tariff (covering all renewables) was on average 0.08DKK/kWh (about 0.9p/ kWh) (ENS, 2009). Table 1 ESTIMATED IMPACT OF RENEWABLE ENERGY SUBSIDIES ON ELECTRICITY BILLS IN THE UK, GERMANY AND DENMARK (P/KWH). UK (2011) Germany (2009) Denmark (2011) Total cost of electricity (p/kWh) 13 20.2 25.2 of which: RES policies (RO, EEG, PSO) 0.5 0.9 0.9 other environmental policies 1.4 4.0 8.8 VAT* 0.7 3.2 5.1 *VAT on electricity is 5% in the UK, 19% in Germany and 25% in Denmark Sources: UK data based on DECC (2011a); German data based on BMU (2009); Danish data based on Energitilsynet (2012). 2 Assuming an average consumption of 3,500kWh, as in BMU (2009). Average exchange rate in 2009: 0.891 3 Average exchange rate in 2011: 0.1165 Ev 38 Energy and Climate Change Committee: Evidence

The Future of Onshore Wind Subsidies Ultimately, once all of the failures have been overcome, it is the market that should decide from which sources the UK should obtain its energy. Renewable subsidies are not intended to be permanent and should be gradually reduced over time as more is learned about how to most efficiently manufacture and deploy the technologies, and costs come down. It is yet unclear, however, when exactly onshore wind will become fully competitive with fossil fuel sources, notably with natural gas. Their future relative price depends both on market fluctuations of gas prices and the cost of onshore wind technologies. The figure below show that, depending on the assumptions made, onshore wind could become economically competitive with gas as soon as in the next few years, or as late as after 2040. More realistically, onshore wind is expected to become economically competitive in five–10 years (see eg Bloomberg NEF, 2011), while other renewable generation technologies could become competitive in the 2020s and 2030s (CCC, 2011a). This will also depend, however, on how effective subsidies will be in stimulating learning-by-doing and economy of scales, so that the price of technologies decreases at sufficient speed (Table 2). Table 2 LEVELISED COST AND POTENTIAL DEVELOPMENT OF KEY LOW CARBON ELECTRICITY SOURCES IN THE UK Cost * (p/ 2011 2020 2030 2040 Potential development in 2020–2030 kWh) (TWh/year) Reference technology: unabated gas (ie without CCS) Gas 4.1–7.5 4.8–11.1 5.2–13.8 6–16.5 Technologies likely to play a major role in the future UK energy mix Onshore 6.6–9.3 6–8.5 5.2–7.4 4.7–6.9 From 7 TWh in 2010 to 30 TWh in 2020, up to 60 TWh in 2030 Offshore 11–19.7 9.2–18.6 6.9–16.5 5.5–14.6 From 3 TWh in 2010 to 50 TWh in 2020, up to 180 TWh in 2030 New nuclear 5.5–13.1 4.7–12.9 3.8–12.4 3.2–11.7 From 80 Twh in 2010 to 175 by 2030 Technologies that could play a major role, where deployment in the UK is important in developing the option CCS (gas) 6.3–17 5.9–16.7 5.5–16.3 5.2–16 Uncertain CCS (coal) 8.9–21.3 8–21 6.9–20.4 6.3–19.9 Uncertain Tidal 16.6–39.5 12.6–37.4 9.4–34 7.4–30.8 From 0 today to <3TWh in 2020, up to 8 TWh in 2030 Wave 22.5–50.5 15.5–47.4 11–42.4 8.7–37.8 From 0 today to <3TWh in 2020, up to 7 TWh in 2030 Technologies that could play a major role, but limited role for UK deployment in developing the option PV 22.8–42.6 12.7–30.4 7.6–22.3 5.3–17 From ~0 today up to 19 TWh in 2030 (limited role in 2020) *Costs are for a project starting construction in that year, discounted at high and low discount rates (7–10%). Estimates take into account capital, fuel and carbon price uncertainty. Additional system costs due to intermittency (eg back up, interconnection) are not included. Sources: Levelised costs from CCC (2011b); potential development to 2020 from ENSG (2012) and to 2030 from Arup (2011), except new nuclear from CCC (2011b). As a relatively mature technology, onshore wind’s capital costs are not expected to fall very quickly in the next decades. The Department for Energy and Climate Change estimated its levelised costs to come down by around 8–9% over the period 2010 to 2030, and devised to cut the level of subsidy by a commensurate amount as from 2013 (DECC, 2001b) . Any further decrease of the subsidy should be accompanied by a careful analysis of future costs improvements. Energy and Climate Change Committee: Evidence Ev 39

Figure 1 HIGH AND LOW ESTIMATES OF LEVELISED COSTS FOR ONSHORE WIND AND UNABATED GAS (2011–2040) 18

16 Gas - high estimate

14

12

10

p/kWh 8 Wind - higfh estimate 6 Gas - low estimate Wind - low estimate 4

2

0 2011 2020 2030 2040

Source: Based on data from CCC (2011b) - high and low interest rate (7-10 per cent)

Source: Based on data from CCC (2011b)—high and low interest rate (7–10%) Overall, it is important that the gradual decrease and eventual phasing-out of subsidies is done: — in a robust way, so that the subsidy reduction is proportional to the expected reduction in technology costs. Issues of asymmetric information can be (at least partially) addressed by requiring renewable electricity generators to disclose some of their cost-related information to the regulators in exchange for the subsidies; — in a predictable way, with the criteria and timetable for decisions being clear and transparent, in order to avoid ad-hoc and sudden changes in subsidy levels creates policy risks which act as a disincentive to private investors and increase energy costs; and — In a consistent way which is coherent with public policies on climate change, including the national carbon reduction targets and the renewable energy targets.

References Arup, 2011. Review of the generation costs and deployment potential of renewable electricity technologies in the UK. Study report. [online] Available at: http://www.decc.gov.uk/assets/decc/11/consultation/ro-banding/3237-cons-ro-banding-arup-report.pdf Bassi, S., Bowen, A. and Fankhauser, S. 2012. The case for and against onshore wind energy in the UK. [pdf]. London: Grantham Research Institute. Available at: http://www2.lse.ac.uk/GranthamInstitute/publications/Policy/docs/PB-onshore-wind-energy-UK.pdf Bloomberg New Energy Finance (NEF), 2011. Onshore wind energy to reach parity with fossil-fuel electricity by 2016. [Press release], 10 November 2011, Available at: http://bnef.com/PressReleases/view/172 Committee on Climate Change (CCC), 2011a. Renewable Energy Review. [pdf] London: CCC. Available at: http://www.theccc.org.uk/reports/renewable-energy-review Committee on Climate Change (CCC), 2011b. Costs of low carbon generation technologies—2011 Renewable Energy Review—Technical Appendix. [pdf] London: CCC. Available at: http://hmccc.s3.amazonaws.com/Renewables%20Review/ RES%20Review%20Technical%20Annex%20FINAL.pdf Danish Energy Agency (ENS), 2009. Wind turbines in Denmark. [pdf]. Copenhagen: ENS. Available at: http://www.ens.dk/en-US/supply/Renewable-energy/WindPower/Documents/ Vindturbines%20in%20DK%20eng.pdf Department of Energy and Climate Change (DECC), 2011a. Estimated impacts of energy and climate change policies on energy prices and bills. [pdf] London: DECC. Available at: http://www.decc.gov.uk/en/content/cms/meeting_energy/aes/impacts/impacts.aspx Department of Energy and Climate Change (DECC), 2011b. Consultation on proposals for the levels of banded support under the Renewables Obligation for the period 2013–17 and the Renewables Obligation Ev 40 Energy and Climate Change Committee: Evidence

Order 2012. [pdf] London: DECC. Available at: http://www.decc.gov.uk/assets/decc/11/consultation/ro- banding/3235-consultation-ro-banding.pdf Electricity Networks Strategy Group (ENSG), 2012. Our Electricity Transmission Network: A Vision for 2020—An Updated Full Report to the Electricity Networks Strategy Group. [pdf] London: Department of Energy and Climate Change. Available at: http://www.decc.gov.uk/assets/decc/11/meeting-energy-demand/future-elec-network/4263-ensgFull.pdf Energitilsynet, 2012. Gennemsnitlige månedlige elpriser for forbrugere og virksomheder i Danmark (Average monthly electricity costs for consumers and businesses in Denmark) [in Danish]. [online] Available at: http://energitilsynet.dk/el/priser/prisstatistik/ Eurostat 2011. Energy price statistics—tables and figures. [online]. Available at: http://epp.eurostat.ec.europa.eu/statistics_explained/index.php/Energy_price_statistics Federal Ministry for the Environment, Nature Conservation and Nuclear Safety (BMU), 2009. Electricity from renewable Energy Sources—What Does it Cost? [pdf]. Bonn: BMU. Available at: http://www.bmu.de/files/pdfs/allgemein/application/pdf/brochure_electricity_costs_bf.pdf Her Majesty’s Government, 2011. The Carbon Plan: Delivering our low carbon future. [pdf] London: HM Government. Available at: http://www.decc.gov.uk/assets/decc/11/tackling-climate-change/carbon-plan/3702- the-carbon-plan-delivering-our-low-carbon-future.pdf Her Majesty’s Treasury, 2011. Carbon price floor consultation: the Government response. [pdf]. London: HM Government. Available at: http://www.hm-treasury.gov.uk/d/carbon_price_floor_consultation_govt_response.pdf Her Majesty’s Treasury, 2012. Budget 2012 policy costings. [pdf]. London: HM Government. Available at: http://cdn.hm-treasury.gov.uk/budget2012_policy_costings.pdf Organisation for Economic Co-operation and Development (OECD), 2011. Inventory of estimated budgetary support and tax expenditures for fossil fuels. [pdf]. Paris: OECD. Available at: http://www.oecd.org/dataoecd/40/35/48805150.pdf July 2012

Written evidence submitted by Jeremy Elgin Background I am a farmer in Buckinghamshire working on submitting a planning application for a single medium scale turbine—which will be used to supply electricity to the farm as well as the grid. I am prepared to give oral evidence if required. My main issue in proceeding with my project has been coping with the complexities of the planning system, combating many of the urban myths surrounding wind turbines and persuading local acceptance for the project. On local acceptance, I have found that there is widespread support from a largely silent majority. There is recognition that wind turbines can and should play a significant role in the UK’s energy generation, and our reliance on fossil fuels is detrimental both from an environmental standpoint, but also from fiscal and energy security points as well. The opposition is centred on a relatively small number of individuals, who are well educated, well funded and locally influential. Cutting through the smoke screen of objections, the overriding issue is that of the possible effect on house prices. This is tied in with, or leads to, a total denial of the need to upgrade the UK generation and distribution infrastructure. With some there is recognition for the need of wind, but “only in appropriate places”—this translates to not anywhere near me, and the definition of “appropriate” is strangely elusive. In terms of making them more acceptable to local communities, the key is to make the benefit of the turbine available to the immediate local community. I do not think that just making contributions to a community fund is the right answer as the benefit is not readily identifiable with the project and many of the objectors are not users of local services, nor do they get much involved in the Parish Council etc. If owner/operators could make electricity at a reduced rate available to those nearby, perhaps via the local authority then I think there would be some change in attitude. The intermittency of wind is often raised, and again I would like to see more emphasis/publicity on —ie pumped storage (like Dinorwig), fuel cells for augmenting the grid and use in vehicles (future). Subsidy levels—subject to urban (or rural) myths—I will receive huge subsidies even if it does not work. The level of subsidy for on shore wind is towards the bottom of the FIT/ROC schemes. While some figures are available it is difficult to compare total support given to renewables as compared to other forms of generation ie nuclear and fossil fuel with ccs. Energy and Climate Change Committee: Evidence Ev 41

I am convinced that onshore wind has to be amongst the most cost effective form of generation. Unlike any other form of generation, I know what my construction costs are likely to be and I know what my fuel costs will be over the length of operation (zero) and I have a good idea of what my decommissioning costs will be. No other generator can say that. The request for consultation asks if it is possible to quantify how much consumers/tax payers pay for wind. Given the way support is structured (generation specific) I would hope that this is feasible—but comparisons should be given for all forms of generation and include total cost, not just the subsidy (so as to give an accurate overall cost price per KWh including fuel, CCS, decommissioning, etc). The recent decisions by various local government authorities to try and oppose further development, and the publicity around these moves, has not been helpful (ie min separation distances from dwellings). These actions appear (to a lay person such as myself) to be in opposition to the NPFF and associate guidance from central government on renewable energy. Developers, such as myself, find ourselves in the situation where we a perusing a course encouraged by central government, but frustrated by local government. The Planning Inspectorate can provide remedy, but it does add significantly to the risk, cost and time. On the planning issue, the only other point I would make is that the MOD now only respond to radar clearance once a planning application is submitted. Surely, the MOD could and should respond at a pre investment/screening stage. In conclusion I would say that renewables in general and onshore wind in particular should remain supported and more must be done by all parties to inform the public as to the challenges and costs involved to providing a solution for our energy needs. June 2012

Written evidence submitted by the Centre for Energy Policy and Technology, Imperial College Covering Note ICEPT is an interdisciplinary research centre focused upon the interaction of technology and policy. From its base at Imperial College, the centre is uniquely placed to gather insights into technological and scientific developments relevant to contemporary debates in energy policy. ICEPT is funded by a wide range of bodies, including UK research councils, industry, the EU, and NGOs. It is independent and does not exist to promulgate any particular agenda related to wind, renewables or energy policy more widely. The centre also has policy analysis expertise, drawing upon a wide range of system modelling, scenario and technology assessment techniques. ICEPT runs the Technology and Policy Assessment function of the UK Energy Research Centre (www.ukerc.ac.uk). The reports it produces have been widely cited by select committees and in policy documents. This submission draws upon UKERC reports on the costs and impacts of intermittent generation, investment decisions in electricity generation, and the costs of offshore wind in UK waters. It draws also upon forthcoming UKERC research, which is undertaking a thorough meta-analysis of estimates of the costs of wind, gas, nuclear, solar and CCS. This project also explores the means by which we make judgements on the future costs of power generation. The submission draws upon expertise developed by the authors into the relative costs/ performance of various technologies through a wide range of research projects going back to the early 2000s. The authors experience in meta-analysis indicates the importance of scrutinising methodology carefully, particularly when estimates are outliers emanating from special interest groups. There is considerable agreement around issues, methods and approaches in the international literature from peer reviewed, Government and other reputable sources. This note seeks to present this evidence.

Summary: Key Issues 1. What do cost benefit analyses tell us about onshore and offshore wind compared with other measures to cut carbon? Accounting for the full costs and benefits of different technologies is complex. Complicating factors include potential for cost reduction through deployment (learning by doing), wider industrial or regional benefits, or environmental costs. German cost benefit analyses have been very positive, see point 7 below. Generally speaking decarbonising power generation is more costly than measures to cut demand. However many analyses of long term decarbonisation point to the importance of decarbonising power, with wind a proven and relatively low cost option for doing so. Costs of nuclear and CCS are uncertain, but higher than onshore wind. Offshore wind costs and the costs of first of a kind nuclear/CCS appear similar. In the UK wind also offers a large potential resource. The Annex provides more detail. 2. What do the latest assessments tell us about the costs of generating electricity from wind power compared to other methods of generating electricity? Onshore wind is among the cheapest of the non-fossil options. Wind costs fell steadily during the 1990s until the mid-2000s. Absolute costs for all sources have risen recently due to global commodity prices and market factors, but wind costs relative to other generation options have declined, see Table 1 in the Annex. By the mid 2020s the range of forecast costs for onshore wind and gas- fired generation (CCGT) show an overlapping range. Gas prices are uncertain and the cost of wind lies in a range due to varying wind speeds/sites. Figure 1 in the Annex shows the results of a meta-analysis of cost Ev 42 Energy and Climate Change Committee: Evidence

estimates from around the world. Onshore wind is currently about 10–15% more costly than gas in a UK context, and cheaper than estimates for new nuclear. 3. How do the costs of onshore wind compare to offshore wind? Figure 1 and Table 1 in the Annex show that onshore wind costs are substantially below offshore wind, with onshore currently costing around 40% less per unit of electricity. What Figure 1 also shows is that most analyses suggest that the scope for cost reduction in offshore wind is considerably greater than the scope for cost reductions onshore, since the onshore wind industry is relatively mature, and the opportunities for continued cost reductions offshore are more substantial. Details on the sources of cost reduction offshore are provided in the Annex. 4. What are the costs of building new transmission links to wind farms in remote areas and how are these accounted for in cost assessments of wind power? Transmission requirements associated with the Government’s plans for renewable energy have been assessed in great detail by network operators, utilities, experts, DECC and Ofgem. This Electricity Network Strategy Group (ENSG) first reported on the transmission costs of the 2020 targets in 2009.1 The estimates were updated in February 2012.2 The ENSG estimate from 2009 was that around £4.7 billion in total investment in transmission upgrades would be needed to accommodate a mix of onshore and offshore wind, together with other changes to the generation mix. 4.1 A 2011 report from the CCC3 annualised the ENSG expenditure estimate of £4.7 billion, and distributed it over anticipated electricity demand.4 The resulting 0.1 p/kWh on bills is reported in the CCC note on bills.5 The annualised cost amounts to £275 million per year from 2020 on. If we assume 29 million households in 2020, with households accounting for around 30% of demand, the annual cost is around £3.20 per household per year. The latest ENSG capital cost estimate is rather higher at £8.8 billion. Very approximately therefore the estimated transmission cost per household should be increased to around £5.70 per year. These costs are not attributed to individual wind farms. 4.2 Offshore network costs are paid for by generators, are borne directly by offshore wind farms and hence already show up in analyses of the costs of the RO, outlined below. 5. What are the costs associated with providing back up capacity for when the wind isn’t blowing, and how are these accounted for in cost assessments of wind power? The costs and impacts of the “intermittent” nature of wind any other renewables has been comprehensively studied by academics, utilities and consultancies from around the world. A thorough systematic review and meta-analysis by the authors in 2006, with input from a wide spectrum of leading experts, indicated that the cost of intermittency amounted to around 0.5 to 0.8 pence per kWh of wind generation, should intermittent generation reach around 20% to 25% electricity supplied in Britain.6 This work needs updating to reflect 2012 costs, which will be higher, since electricity costs have risen. But more recent analysis by Poyry for the Committee on Climate Change, combined with the ENSG data, provides an indication that the 0.8 p/kWh figure is broadly consistent with contemporary analysis.7 0.8 p/kWh of wind is equivalent to annual expenditure of approximately £600 million, at 20% renewables, or £740 million for 25% renewables. Assuming the domestic sector bears 30% of this, the cost per household for intermittency in 2020 is around £6 to £8 per year.8 6. How much support does wind power receive compared with other forms of renewable energy? Is it possible to estimate how much consumers pay towards supporting wind power in the UK? (ie separating out from other renewables) Ofgem produce an annual report on the Renewables Obligation (RO) which identifies the total value of the support provided and the share for each technology. For the most recent data (2010–11),9 the total annual value of support for all renewables through the RO was £1.28 billion, with onshore wind accounting for 30.9% (£395 million) and offshore wind accounting for 20.2% (£258 million).10 Assuming the domestic sector bears 30% of this across 29 million households, then this translates to around £6.75 per household for onshore and offshore wind combined, compared to around £6.50 for all other renewables. Renewables can exert downward pressure on wholesale electricity market prices. This can partially offset the costs of the RO. By 2020 DECC estimate that the effect on wholesale prices will amount to a bill reduction of £20 per household/yr. More details in the Annex. 7. What lessons can be learned from other countries? The evidence suggests that stable and investable policies—in particular fixed Feed in Tariffs, FiTs, bring down costs, create industries, allow consumers to invest and generally maximise social benefits. The evidence that more competitive schemes do more to reduce costs is questionable. Indeed the academic evidence suggests that the UK NFFO in the 1990s, an auction based scheme, favoured the big utilities, was antagonistic to domestic manufacturers, created a perceived “rush” for the best locations, often also the most scenic, and led to disappointing levels of delivery. By contrast, the fixed FiTs in our near neighbours provided a simple and stable system that allowed large levels of local/community ownership and lots of new entrants. This was assisted in some instances through favourable loan schemes from community or state backed banks.11 Germany has assessed costs and benefits associated with its FiTs and found a strongly positive economic benefit.12 However the international experience is mixed. Alongside positive experiences are examples of things going wrong; tariffs, planning, grid management.13 8. What methods could be used to make onshore wind more acceptable to communities that host them? Evidence from countries where wind has already been developed on a much larger scale (eg Denmark and Germany) suggests that there is a direct relationship between the extent to which local people can take a meaningful stake in a wind farm, and the extent to which local people object to wind development.14 The potential for community ownership is further enhanced if financial vehicles exist to facilitate it, as noted above. Energy and Climate Change Committee: Evidence Ev 43

In the UK context the most straightforward way to encourage greater community/local owned schemes would be to extend the micro-generation FiT for wind from 5 MW to perhaps 50 MW, so that smaller wind farms could benefit from the simplicity and revenue stability that the FiT can provide relative to the RO, and proposed CfD.15

Technical Annex Relative Costs of Wind and other Technologies Figure 1 is based upon ongoing UKERC research, which is undertaking a thorough meta-analysis of estimates of the costs of electricity generation technologies, examining how those estimates are arrived at, and assessing what lessons can be drawn from the accuracy or otherwise of past estimates and projections. The left hand half of the diagram shows the historical trajectory of the average (mean) of Europe-wide estimates for electricity generation costs for onshore wind, offshore wind and gas-fired plant. The wide range of UK forecasts, shown on the right hand half of the diagram, result from differing assumptions that studies have adopted for key cost drivers such as capital and operating costs, plant load factors, fuel costs (in the case of gas plant), and discount rates. These estimates do not take into account intermittency/network costs, which tend to increase system costs, or “merit order effects” (see below) which tend to decrease system costs.

Figure 1 COMPARATIVE COSTS OF ELECTRICITY FROM CCGT, ONSHORE AND OFFSHORE WIND16 In-year mean (Europe) and UK forecasts 200

180

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100

80 2011/£/MWh 60

40

20

0 1995 2000 2005 2010 2015 2020 2025 2030 Year Onshore wind, contemporary estimates Onshore wind, forecasts

CCGT, contemporary estimates CCGT, forecasts

Offshore wind, contemporary estimates Offshore wind, forecasts

Onshore wind, contemporary estimates Onshore wind, forecasts

CCGT, contemporary estimates CCGT, forecasts

Offshore wind, contemporary estimates Offshore wind, forecasts

Support for Wind in other Countries—Feed in Tariff Rates in the EU Figures 2 and 3 show FiT rates for selected European countries, for onshore and offshore. This indicates that the UK (assuming 1 ROC for onshore) is towards the upper end of payment levels for onshore wind. UK offshore wind tariffs look around average in comparison to other EU country tariffs. However, both The and Germany use a range of tariff rates; an average of the rate is given in Figure 3. The German tariff is dependant on the duration of payment and scheme chosen by system operator, whilst The Netherlands uses four stages of subsidy level that is allocated on a first come first serve basis. It is important to note that both The Netherlands and Germany have much higher rates than the UK at, 23.37 and 23.62 GBP pence/kWh respectively. When, where and how these rates are employed will determine how attractive these countries offshore tariffs are in relation to other country tariffs. UK figures assume £48/MWh for ROCs (2011 ERoc average), and wholesale price of £55/MWh. The latter figure is obviously quite variable, having reached £80/ MWh in 2008 and varying between £38 and £58 during 2010 and 2011.17 Ev 44 Energy and Climate Change Committee: Evidence

Figures 2 and 3

WIND TARIFFS IN SELECTED COUNTRIES18

Selected EU onshore primary wind tariffs in GB pence/kWh

12 10 8 6 4 2 0

Spain France Ireland Austria Finland Slovakia Belgium Germany UK 1 ROC

Onshore tariffs: Currency conversion to GBP as of 28 June 2012, EUR = 1.243 GBP. All rates valid for 2012. Austria rate for 2012–2013; Belgium rate set in 2006, set as a minimum price of certificates; Finland current price valid until end of 2015; France current price set in 2008; Germany price set in 2012, range of rates (average presented in graph); Ireland current price for 2012; Slovakia price set in 2009 valid for 3 years, finishing in 2012; Spain set in 2007 current price.

Selected EU offshore primary wind tariffs in GB pence/kWh

20

15

10

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0

France Belgium Germany UK 2 ROC Netherlands

Offshore tariffs: Currency conversion to GBP as of 28 June 2012, EUR = 1.243 GBP. All rates valid for 2012. Germany and Netherlands rates are averages of a range of rates provided. Netherlands; 14.05–23.37. Germany; 4.35–23.62.

Sources of Cost Reduction Offshore

Whilst onshore wind is a comparatively mature industry with relatively limited scope for major cost reductions (especially since cost savings through increased unit size are limited by physical constraints on handling very large components such as the turbine blades on land), the scope for cost reductions in offshore wind is significant. Major areas of potential cost reduction include increasing turbine size, the introduction of turbines designed specifically for offshore (rather than adapted from onshore designs), improvements in installation techniques, and enhanced reliability through design and optimised maintenance regimes to maximise plant availability and therefore load factor (a key driver of generation costs for wind plant). In addition, the increasing size of the offshore wind market is attracting new entrants, improving competiveness and building confidence and resilience in the supply chain.19 Energy and Climate Change Committee: Evidence Ev 45

Table 1

COST RISES BY TECHNOLOGY20 2006 2009 % rise in levelised cost £/MWh £/MWh 250 CCGT £42 £80

200

Coal £32 £102 150

Nuclear £46 £97 100

Onshore £66 £88 50 wind

0 Offshore £99 £149 Onshore wind Offshore wind CCGT Nuclear Coal wind Technology

Costs per Tonne of Carbon Saved

Cost per tonne of carbon saved will depend upon a range of factors, these include the cost and financing assumptions made about the wind farm, nature of plant displaced, any wider impacts such as emissions in wind farm construction or from back up plant. There is widespread agreement that the lifecycle emissions associated with wind are small, of the order of 10g/kWh (compared to 380g/kWh for gas plant). Analyses of the impacts of intermittency reviewed by the authors also indicate that any emissions from back plant or extra spinning reserve amount to a few percent at most of the emissions savings from wind that result from reduced use of fossil fuel plant.21

One of the simplest representations of abatement cost is the so called “MAC” or Marginal Abatement Cost curve. Over reliance upon them has been criticised for failing to recognise dynamic effects and cost reduction over time, and interactions between choices of technologies and between sectors.22 It also does not account for the volume of abatement possible over time. Nevertheless most assessments show wind to be a “mid range” contender, more expensive than energy efficiency but cheaper than many other “supply side” options.

Wind and Wholesale Price Formation (the “Merit Order Effect”)23

Wind power is generated at near zero marginal cost and is therefore generally dispatched when it is available. In the short-term, where the rest of the generating capacity remains unchanged, wind power therefore pushes high marginal cost plant out of the generating mix and wholesale spot prices become depressed, especially at times when wind output is high. This “displacement” effect is illustrated in Figure 1 where wind is characterised as reducing residual demand because it is always dispatched (subject to transmission constraints). During periods of very high wind (and low demand), where wind output exceeds demand, prices in the GB market could go negative since wind operators would still be willing to trade in the market so long as the price they “pay” is less than the value of a Renewable Obligation Certificate. This will be exacerbated if thermal capacity is kept running to avoid cycling costs.

Similar conditions occur in other markets, since the Feed in Tariffs common in other countries also insulate wind generators from wholesale price movements. Indeed in many instances renewables are given priority access by system operators. Studies from overseas are therefore relevant to the British situation and numerous modelling and empirical studies have attempted to estimate the impact of renewables on electricity markets. These studies all conclude that wind will depress prices. For example: Ev 46 Energy and Climate Change Committee: Evidence

— Sensfuss et al (2008) use a simulation model to estimate the impact of renewables (mainly wind) on spot market prices in Germany. They estimate that a wind penetration of around 10% in 2006 (52 TWh) results in a reduction of average spot price of €7.83/MWh (approximately 15%), compared to a counterfactual with no wind. Neubarth et al (2006) conduct a statistical analysis of time-series data in Germany in 2004/5 when wind penetration was around 5%, concluding that wind power reduces the average daily spot market price by €1.89/MWh for every GW of average available wind energy. They estimate that the 18.4 GW of installed capacity resulted in an overall average price reduction of €6.08/MWh (approximately 12%). — A modelling study by the regulatory authorities in Ireland (CER and UREGW, 2009) looked at the effect of wind on wholesale prices under a range of scenarios with wind penetrations ranging from 16% to 42% and with different mixtures of conventional generation. For most of the scenarios prices were significantly depressed (by between 9 and 21%). However, the exception was a scenario which assumed a high proportion of Open Cycle Gas Turbines (OCGTs), where prices were 10% higher than the counterfactual. — Moesgaard and Morthorst (2007) statistically analyse spot prices between 2004 and 2007 in Western Denmark and concluded that they were reduced by 5–15% as a result of wind power. During this period the penetration of wind was approximately 20–25%. In summary, these studies generally conclude that wind has a negative impact on average spot prices of the order of 1% for every 1% of additional wind penetration. Price effects may be more extreme under similar wind penetrations in GB because it has relatively low supply-side flexibility—interconnection and hydropower capacity—to balance fluctuations in wind output, compared to some of the countries studied above (DECC, 2009b). In the long term, where the make-up of the conventional generation mix can change more radically (through closures and new build), it is more difficult to predict the impact of wind on electricity prices. The lower load factors experienced by plants with relatively high capital costs (and low marginal costs) means they may be replaced by peaking plants with low capital cost and higher marginal costs, such as OCGTs (Nicolosi and Fursch, 2009; Saenz de Miera et al, 2008). This would push up average prices (see Figure 4).

Figure 4 THE LONG-TERM IMPACT OF WIND ON ELECTRICITY PRICES (AUTHOR’S ILLUSTRATION)

Figure 1 is an illustrative representation of equilibrium prices in two peak demand scenarios: (i) where the conventional generation mix order remains dominated by CCGTs and coal stations and (ii) where the conventional generation mix is adapted to a high wind penetration with higher proportion of higher marginal cost plants (such as OCGTs). Under a standard generation mix, the market clears at PSL and PSH under high and low wind conditions respectively. Under a “wind-adapted” generation mix, the corresponding prices are higher, at PAL and PAH. In this way, the dynamics of the conventional generation mix as a response to wind could work to push up electricity prices in the long-term. This could partially offset or even exceed the “displacement” effect of wind.

References 1. http://webarchive.nationalarchives.gov.uk/20100919181607/http://www.ensg.gov.uk/assets/ensg_ transmission_pwg_full_report_final_issue_1.pdf 2. http://www.decc.gov.uk/en/content/cms/meeting_energy/network/ensg/ensg.aspx Energy and Climate Change Committee: Evidence Ev 47

3. http://www.theccc.org.uk/reports/household-energy-bills

4. 320 TWh—Personal Communication with the CCC secretariat, February 2012.

5. http://www.theccc.org.uk/reports/household-energy-bills

6. See http://www.ukerc.ac.uk/support/Intermittency and Gross R, Heptonstall P, 2008, The costs and impacts of intermittency: An ongoing debate, Energy Policy (36) Pages: 4005–4007; Skea J, Anderson D, Green T, Leach, M, 2008, Intermittent renewable generation and maintaining power system reliability, IET Generation, Transmission & Distribution, (2) Pages: 82–89; 2007, Renewables and the grid: understanding intermittency, Proceedings of ICE Energy (161) Pages 31–41.

7. The CCC’s 2011 total figure is 1 p/kWh for intermittency and transmission combined, and as noted above, the transmission cost element is around 0.1 p/kWh of intermittent renewables.

8. Assumes 29 million households and electricity sales of 370 TWh, households 30% of sales. The UKERC work also notes that cost estimates lie in a range, which depends upon the nature of the system (extent of interconnection, availability of demand response, mix of fossil/nuclear plant) mix of renewables and operational rules for the System Operator.

9. See Renewables Obligation Annual Report 2010–2011, Ofgem, London, available from http://www.ofgem.gov.uk/Pages/MoreInformation.aspx?docid=278&refer=Sustainability/Environment/ RenewablObl

10. Landfill gas accounted for 20.1% (£257 million), biomass including co-firing 19.4% (£248 million), hydro power 7.5% (£96 million), with the remainder including sewage gas and PV accounting for around 2% (£26 million).

11. See Gross R, Heptonstall P, 2010, Liberalised Energy Markets: an obstacle to Renewables? In Rutledge I, Wright P (eds), UK energy policy and the end of market fundamentalism, Oxford University Press, Oxford.

12. German data is presented in http://www.dbcca.com/dbcca/EN/_media/Paying_for_Renewable_Energy_ TLC_at_the_Right_Price.pdf

13. Deutsche Bank retains a wide ranging library of international review papers http://www.dbcca.com/dbcca/ EN/investment_research.jsp

14. As 11.

15. The proposed CfD should offer revenue stability overall, but this will be subject to securing a PPA and achieving the reference price for power output. At the time of writing the micro-gen FiT apears far simpler.

16. This graphic appeared in the Guardian and is based on data collected by the authors for UK Energy Research Centre project: http://www.ukerc.ac.uk/support/tiki-index.php?page=Cost+Methodologies

17. http://www.decc.gov.uk/assets/decc/11/about-us/economics-social-research/3593-estimated-impacts-of-our- policies-on-energy-prices.pdf

18. http://www.e-roc.co.uk/trackrecord.htm http://www.consumerfocus.org.uk/policy-research/energy/paying-for-energy/wholesale-retail-prices http://www.decc.gov.uk/assets/decc/11/about-us/economics-social-research/3593-estimated-impacts-of-our- policies-on-energy-prices.pdf http://www.res-legal.de/en/search-for-countries.html

19. Greenacre P, Gross G, Heptonstall P, 2010, Great Expectations: The cost of offshore wind in UK waters, UK Energy Research Centre, London, http://www.ukerc.ac.uk/support/tiki-index.php?page= Great+Expectations:+The+cost+of+offshore+wind+in+UK+waters

20. Adapted from: Heptonstall P, Gross R, Greenacre P, Cockerill T, 2012, The cost of offshore wind: Understanding the past and projecting the future, Energy Policy (41) Pages 815–821.

21. http://www.ukerc.ac.uk/support/Intermittency

22. http://www.whoseolympics.org/bartlett/energy/news/documents/ei-news-290611-macc.pdf

23. Excerpt from Steggals W, Gross R, Heptonstall P, Winds of change: How high wind penetrations will affect investment incentives in the GB electricity sector, Energy Policy, 2011, Vol:39, Pages:1389–1396. June 2012 Ev 48 Energy and Climate Change Committee: Evidence

Supplementary evidence submitted by Dr Robert Gross and Phil Heptonstall, Centre for Energy Policy and Technology, and Professor Richard Green and Dr Iain Staffell, Business School, Imperial College London Preamble This note is in addendum to the written and oral evidence Dr Gross submitted to the 10th July one off hearing on this topic. It addresses some of the specific contentions made by Professor Gordon Hughes on behalf of the Global Warming Policy Foundation (GWPF). The main issue the note addresses is the system implications of integrating wind, including Prof. Hughes’ contention that meeting the UK’s renewable energy targets using wind power will require up to 21GW of dedicated back up plant and do little or nothing to reduce CO2 emissions. However, a number of additional errors and misapprehensions in Prof. Hughes evidence to the Committee are also addressed. The note provides a high level overview of key issues. Readers who wish to understand the grid implications of integrating renewables are referred to the authors’ review and meta-analysis of existing estimates on this topic for the UK Energy Research Centre (UKERC), and to a number of recent publications commissioned by the Committee on Climate Change and the Department of Energy and Climate Change (DECC).4 The UKERC review provides a bibliography of over 100 international peer reviewed academic, system operator and government papers and reports dealing with this important topic. Readers who wish to understand the optimisation problem associated with investment in various types of new power stations are referred to the authors’ recent conference paper for the British Institute for Energy Economics (BIEE).5 The sections that follow deal with key problems with the GWPF evidence to the Committee in the following order: The volume of wind needed to meet targets; the cost of wind; the potential for the system to absorb wind; the carbon abatement implications of a system containing substantial wind power. This order has been chosen because Prof Hughes’ contentions about system balancing requirements and carbon abatement follow in part from his view of wind capacity requirements. In order to assess Prof Hughes assertions about CO2 emissions we also discuss his paper for the GWPF, which describes three “scenarios” related to wind power and power system operation (Annex 1). We then use an economic model of the energy system to show what an economically rational approach would suggest (Annex 2). Finally, we provide some relevant background information in the form of statistics and explanation around wind speeds (Annex 3). The authors have no connection with the wind industry and no vested interest in the debate. This addendum has been prepared to correct a series of misrepresentations related to the cost of wind, operation of power systems and the impact of wind power thereon.

Meeting the UK targets: How much wind is needed? Prof Hughes suggests that 36 GW of wind will need to be installed to meet UK renewable energy targets in 2020. The government has not set a specific target for wind (onshore or offshore). Various scenarios exist, usually derived from cost-optimising models of the power system which seek to determine a likely electricity supply mix consistent with meeting targets at least cost. National Grid’s “gone green” scenario, used to assess requirements for transmission network upgrading, suggests that up-to 26 GW of wind could be installed by 2020.6 DECC’s latest “roadmap” for renewable energy suggests that by 2020 some 10 to 19 GW of onshore wind and 13 to 26 GW offshore could be installed, with mid ranges of 13 GW onshore and 18 GW offshore (31 GW in total).7 Previous DECC estimates have suggested that some 15 GW onshore and 13 GW offshore could be installed in 2020,8 28 GW in total. The Committee on Climate change (CCC) also offer deployment estimates equivalent to around 27 GW.9 The CCC has further recommended that the offshore target should be limited to 13 GW unless costs fall.10 Hence, at least three credible sources provide estimates for installed wind in 2020. The range of estimates is between 26 GW and 31 GW, with most below 30 GW. Currently there is a total of around 20 GW (both on and offshore) in the development pipeline, with about 7 GW installed to date. Hence a plausible outcome based upon actual plans and proposals for 2020 is approximately 27 GW. Prof. Hughes overstates the volume of wind anticipated in 2020. His estimate is 10 GW higher than the estimate used by National Grid to plan for network expansion and at least 5 GW higher than the central range of the DECC figures. It is 9 GW above current plus planned projects. 4 http://www.ukerc.ac.uk/TPA Intermittency Project http://www.decc.gov.uk/en/content/cms/meeting_energy/network/strategy/ strategy.aspx 5 Staffell, I & Green, R 2012, “Is there still merit in the merit order stack”, BIEE September 2012 Conference Proceedings. See also Stoft, S. 2002. “Power System Economics—Designing Markets for Electricity”, IEEE Press, Piscataway, NJ. 6 http://www.nationalgrid.com/uk/Electricity/Operating+in+2020/ 7 http://www.decc.gov.uk/en/content/cms/meeting_energy/renewable_ener/re_roadmap/re_roadmap.aspx 8 DECC Renewable Energy Strategy, cited by the Committee on Climate Change http://hmccc.s3.amazonaws.com/ Renewables%20Review/CCC_Chapter%202.pdf 9 22 GW from 2010 to 2020, with around 5 GW installed in 2010 http://hmccc.s3.amazonaws.com/Renewables%20Review/CCC_ Chapter%202.pdf 10 http://www.theccc.org.uk/reports/renewable-energy-review Energy and Climate Change Committee: Evidence Ev 49

What are the capital costs of wind to meet 2020 targets? Prof. Hughes also suggests that the capital cost of installing wind to meet 2020 targets, including transmission upgrades, will be £124 billion. As noted, approximately 7 GW of wind is already installed in the UK. Assuming that a ballpark 27 GW is consistent with the range of studies reviewed above then some 20 GW is needed to 2020. 10 GW onshore would cost approximately £13 billion. A further 10 GW offshore would cost £31 billion—assuming no cost reductions.11 The Electricity Networks Strategy Group12 has estimated that the transmission upgrades needed to meet renewable energy targets will be £8.8 billion—giving approximately £53 billion in total for new construction. This does not account for cost reductions, but recent studies suggest the costs of offshore wind could come down by 10–30% over the years to 2020.13 Existing capacity will have been built at a range of costs, generally below current levels (the costs of power generation escalated during the 2000s14). We assume £5 billion to date. Our rough estimate of the costs of wind to 2020, including projects already constructed, but not allowing for cost reductions in future, is therefore below £60 billion, less than half the figure suggested by the GWPF. Prof Hughes appears to have costed the entirety of his 36 GW at current offshore wind costs. His costing of transmission upgrading is not consistent with National Grid. For reasons discussed below, his estimate of “back-up” costs is questionable. He suggests that the capital costs for wind should be increased because wind farms are expected to have shorter operating lives than CCGT stations. This is questionable, but making an appropriate adjustment for this adds less than 10% to the wind costs, and nothing to the costs of longer-lived transmission assets.15 Prof. Hughes estimate of capital costs of wind to 2020 appears to be some £64 billion above what the available evidence suggests, even without allowing for the possibility of cost reductions.

Is there an impending threshold on how much wind the system can absorb? Prof. Hughes states that wind will “begin to impose increasingly heavy costs on system operation as the share of wind power in total system capacity approaches or exceeds the minimum level of demand during the year (base load). This threshold is due to be passed in the UK shortly after 2015.” Prof. Hughes makes a further contention that wind would need to be permanently constrained, to the effect that no more than 20 GW of 36 GW could be fed into the grid at any one time. His calculations of wind farm economics are predicated on the basis that wind would therefore need to be substantially curtailed, which affects the load factor assumptions he uses.16 Both comments show a fundamental misunderstanding of the statistics of wind output, and the means by which engineers assess power system balancing requirements. In layman’s terms the key question is as follows—how often does wind generate at maximum capacity, and how often does this coincide with minimum demand? In even more parochial terms, how often is it extremely windy across the UK on a warm night in August? With 20 to 30 GW of wind installed, statistically the answer is close to zero.17 The reason is found within the wind output statistics. Wind farms can operate in a range of wind speeds, but wind speeds are most frequently found to be towards the lower to middle of this operational range (in statistical terms, wind speeds approximate to a Weibull distribution). This means that wind farms most often operate at a range of outputs between 10% and 50% of peak output and a diversified fleet of wind farms in different geographical locations would very seldom, if ever all operate at peak output at once. In fact the data show that the output of a UK wind fleet would almost never exceed 75% of rated capacity. It is also unusual for outputs to fall below 5% of installed capacity. This output range is consistent with both weather station data and data from operating turbines.18 Annex 3 provides a review of wind output data. In very simple terms, we can therefore assume that with 30 GW installed, wind power will produce, for much of the time, between 3 GW and 15 GW of power. Peak British demand exceeds 60 GW. Daytime demand in winter is typically about 45 GW, peaking to above 60 GW in the early evening. Minimum night time demand in winter is usually above 35 GW. In summer, daytime demand is usually around 35 GW and minimum night time demand about 25 GW. Wind speeds tend to be lower in summer, and higher in winter and autumn. Simply 11 Costs approximated, based upon forthcoming UKERC research into the ranges of estimates of the costs of generation, cited in the author’s previous submission to the ECC on the economics of wind. See http://www.ukerc.ac.uk/TPA Costs Project and also http://www.ukerc.ac.uk/TPA Offshore Wind Project 12 http://www.decc.gov.uk/en/content/cms/meeting_energy/network/ensg/ensg.aspx 13 http://www.decc.gov.uk/en/content/cms/meeting_energy/wind/offshore/owcrtf/owcrtf.aspx 14 http://www.ukerc.ac.uk/TPA Offshore Wind Project 15 The shorter lifetime of wind turbines should be taken into account by charging a proportion of the cost of a replacement station in each of the years after the original wind farm would have closed and then discounting the payments back to the present. . 16 http://www.thegwpf.org/wp-content/uploads/2012/08/Hughes-Windpower.pdf 17 See the UKERC review for an exposition of the key principles employed in power system operation http://www.ukerc.ac.uk/ TPA Intermittency Project 18 Staffell, I & Green, R 2012, “Is there still merit in the merit order stack”, BIEE September 2012 Conference Proceedings Ev 50 Energy and Climate Change Committee: Evidence

put, when wind data and demand data are looked at carefully we find that there is very seldom any need to spill wind.19

A more technical explanation can also be provided. In order to determine whether wind power will exceed demand, it is necessary to model wind farm outputs and compare these to demand profiles across the diurnal and annual cycles. This can be done using a system simulation or a statistical simplification thereof. As already discussed, numerous studies have done this for the UK and elsewhere, and detailed statistical studies and simulation models find there is very seldom any need to curtail wind due to insufficient demand. The amount of wind “wasted” is very small.

Power system control requires that wind cannot be the only generation on the network, so the threshold for spilling wind also needs to allow for a minimum amount of conventional plant. Some plants are costly to shut down and restart, and these may need to be given priority over wind at times. Even with these constraints however, Prof. Hughes “threshold” is misleading. Power system simulations run by the Department of Electrical Engineering at Imperial College suggest that, with renewables targets met, and with nuclear and other “must run” plants factored in, the need to spill wind is insignificant in 2020.20 The same study goes onto assess impacts to 2030, concluding that the UK system is well able to absorb a combination of nuclear and new wind, well beyond the 2020 target for wind, with minimal energy spilled. This is consistent with the UKERC review of over 100 international modelling and statistical studies, which indicated that large modern power systems are seldom unable to absorb wind output until wind output is well in excess of 25% of annual demand.21 Modelling of the British system undertaken by the authors indicates that in 2020, with 22 GW of nuclear, 30 GW wind and operational constraints accounted for, only 1 to 2 TWh of wind will be spilled, in a system generating around 350 TWh of electricity.22

In short, Hughes’ contention of a 20 GW cap on the input of wind to the GB power grid makes no sense at all. Curtailment will be required extremely infrequently, and the notion of a generalised 20 GW limit on the amount of wind the grid can absorb is baseless. It does not align with the evidence from simulation studies or indeed a commonsense investigation of the basic statistics.

Does the need for dedicated open cycle gas turbine back-up undermine CO2 savings?

One of Prof. Hughes most startling assertions is that wind needs 21 GW of dedicated gas fired back-up, all of which would be “open cycle” plant and that if the combination of wind and back-up plant is used to replace conventional gas-fired power stations then carbon emissions would rise relative to an all-gas equivalent.

Hughes’ notion of a wind-gas system that is less efficient than an all-gas system might appear compelling. It has been widely reported in newspapers and websites hostile to wind power.23 However it is economically irrational, a nonsense scenario that could not come into being if markets and regulation function as they should to minimise costs and ensure that a sensible mix of power stations gets built. Once built, markets and regulation also ensure that the power stations are used efficiently. Again, the idea that OCGT would displace the output of the most efficient base-load CCGT plant is economically absurd. The least efficient plants have a role, but the role is restricted to short term balancing or peaking. Only if the market and regulatory systems totally fail could Hughes’ scenario of 21 GW of the least efficient gas plants replacing and displacing the most efficient gas plants come to pass. In what follows we try to explain this in lay terms. Annex 1 explains in more detail why the scenarios Hughes describes in his GWPF paper are wrong. Annex 2 provides a more appropriate estimation, using a “despatch” model of the British electricity system.

Open cycle gas turbines—jet engines connected to generators—are only used on a small scale in Britain. They are typically small units of up to 50 MW, much smaller than conventional power stations.. The potential to be stopped and started very quickly also equips them to provide short term system balancing services. The System Operator (National Grid) might contract them to be available to cover for unexpected events, such as a power station breakdown or power line failure. The idea of such plant is that they are used for a short period of time (if used at all), whilst more efficient power stations are made ready, or the fault is repaired, or demand drops. They are also used as “peaking” plant, operating for very short periods when demands are highest and the more efficient plants are already at full stretch. Around 1.5 GW of OCGT is currently installed in Britain,24 and such plants are generally operated at very low load factors—in 2011 they generated less than 25 GWh (0.025 TWh) of electricity (the equivalent of running a mere 16 hours at full load over the whole year).25 19 “Spill” is a short-hand term used in the power system modelling community to refer to available wind output that cannot be absorbed by the electricity network and that is wasted, by reducing the physical output of wind turbines 20 http://www.decc.gov.uk/assets/decc/11/meeting-energy-demand/future-elec-network/5767-understanding-the-balancing- challenge.pdf—the proportion of wind energy spilled ranges from zero to 0.6% 21 http://www.ukerc.ac.uk/TPA Intermittency Project—exceptions to this rule occur for small, island systems, for wind-farms located in remote regions with limited grid capacity and if maximum wind output and minimum demand are strongly positively correlated. 22 Staffell, I & Green, R 2012, “Is there still merit in the merit order stack”, BIEE September 2012 Conference Proceedings 23 For example, Daily Mail, 7 March 2012 and 7 August 2012; European Platform Against Windfarms, http://www.epaw.org/ documents.php?lang=en&article=cost5 24 Digest of UK Energy Statistics 2012 25 Data obtained from Elexon’s TIBCO service. Energy and Climate Change Committee: Evidence Ev 51

Power system modelling undertaken by the authors suggests that the amount of OCGT installed in Britain would be expected to go up in future, in part because of the variable output of wind, which increases the need for short term balancing plant, in part because old coal or oil power stations currently used infrequently to meet peak demands are set to close down. The modelling suggests that in 2020 approximately 10 to 12 GW of OCGT would be needed, used exclusively as peaking/fast response plant and producing for an average of 30 full-load hours per year.26 This compares to the 21 GW, running for long periods, that Prof. Hughes cites in his evidence. We are not able to determine the basis on which Prof. Hughes calculates his estimate for the Committee. We note that it is not consistent with his paper for the Global Warming Policy Foundation, in which he contends that the UK will require some 13 GW of OCGT in 2020.27 Investment in power generation is a complicated optimisation problem; simplistic assumptions, such as those that Hughes makes in his scenario where wind and OCGT replace base-load (see Annex 1) misrepresent reality, and misinform. Under conditions of central planning, monopoly power utilities sought to optimise investment in a mix of power stations such that they constructed the best mix of plants that are expensive to build but cheap to run (nuclear power, more recently wind), and cheap to build but expensive to run (gas OCGT, oil).28 An optimised mix would have just the right amount of inflexible “base-load”, the right amount of “mid-merit” and the right amount of “peaking plant” to meet demand variations and minimise overall capital and running costs. Annex 2 shows how the plant mix might typically meet demand—now and in future. The mix also needs to include plants that are fast responding—OCGTs can fulfil this role, so can hydro, and the latest designs of CCGT. Once plants are built, planners/markets come in play to ensure that power stations are used rationally. OCGTs are considerably less efficient than conventional (combined cycle, CCGT) gas fired power stations. Whilst they are also cheaper to build, the capital cost savings are quickly overwhelmed by increased fuel costs, for anything other than the most short term uses. Under highly competitive liberalised markets investment by private companies should approximate to the planners’ optimum. In the current UK environment, policymakers seeking to assess the plant mix and policy needs of the future might run an investment decisions model that tries to represent how an oligopoly functions.29 With liberalised markets important judgements are needed about what is needed from regulation, for example on whether power price signals alone do enough to promote investment in new power stations, or whether some form of capacity incentive might be needed as well. This goes to the heart of the debate around Electricity Market Reform and is beyond the scope of this note. However, investors and regulators in power generation would have to act extremely irrationally if they were to both make an excessive investment in OCGT, and then to use OCGT extensively to replace the output of more efficient plants. This is the key problem with Hughes’ analysis—irrespective of how much OCGT might be needed to maintain reliable supplies, his scenario where emissions rises vastly exaggerates the extent to which OCGT would be used. Hughes is using OCGT as if it were conventional plant, not specialist, low load factor plant used for short periods when demand is high and wind output low, or when other plants could not come into operation fast enough. The suggestion that as much as 21 GW of open cycle gas turbine plant would need to be built to back-up wind power in Britain is extremely questionable. Using OCGT extensively in place of more efficient and cost effective plant is economically absurd. Hughes suggestion that wind could lead emissions to rise is therefore spurious and misleading. It misrepresents how power systems are operated to maximise efficiency and minimise costs. Annexes 1 and 2 deal with this topic in more depth.

Innovative solutions and the long term In closing this discussion, we also note that the GWPF dismiss the possibility that demand response, storage and transmission upgrades will be able to assist with the integration of wind. This is because Professor Hughes contends “if the economics of such options were genuinely attractive, they would already be adopted on a much larger scale today”. We note the following: Extensive transmission integration already exists between France, Germany and Scandinavia. This allows a more efficient integration of nuclear, coal and hydro. In other words, transmission has already been adopted because it already is economically attractive. The electricity grid in England has long been connected to France, and the Scottish grid to Northern Ireland. Moreover, since the 1970s the French demand profile has been smoothed, using time of day metering and other measures, to help accommodate the output of relatively inflexible nuclear. However, the potential role of demand response will become larger in future because of technological innovation that makes it possible, notably smart meters and appliances. Finally, it seems rather strange to suggest that options that are currently little needed (because to date there has been very little wind power to integrate) would have been adopted ahead of time. It is precisely because 26 Staffell, I & Green, R 2012, “Is there still merit in the merit order stack”, BIEE September 2012 Conference Proceedings 27 http://www.thegwpf.org/wp-content/uploads/2012/08/Hughes-Windpower.pdf 28 Stoft, S 2002. “Power System Economics—Designing Markets for Electricity”, IEEE Press, Piscataway, NJ. Conventional coal and gas plants fall somewhere in between nuclear and OCGT in the spectrum between cheap to run and expensive to build 29 This is done in, for example, Redpoint Energy and Trilemma UK (2010) “Electricity Market Reform Analysis of Policy Options” http://www.decc.gov.uk/assets/decc/Consultations/emr/1043-emr-analysis-policy-options.pdf Ev 52 Energy and Climate Change Committee: Evidence

wind will create significant challenges for power system operation that innovative solutions need to be sought. Analysis by colleagues at Imperial College indicates that the potential for storage, transmission upgrade and demand response to reduce costs increases considerably as we look out to the longer term, to 2030 and beyond, and to a largely decarbonised power system.30 The BritNed to The Netherlands opened in April 2011, and the EirGrid East West Interconnector to the Republic of Ireland in September 2012. National Grid is proposing a line to Belgium that would be ready in 2018.31 In other words, the UK’s interconnection capacity is being increased, strongly suggesting that the extra capacity will be more useful in the near future than it would have been in the past. Decarbonising the power system is a challenging task, one that will of course impose costs. It is important therefore to accurately and fairly represent costs now, in the medium term and in the long term future. Exaggeration and oversimplification do not aid understanding or decision-making. We hope that this note provides helpful clarification of key issues.

Annex 1 NONSENSE SCENARIOS, AND WHY THEY MAKE NO SENSE The GWPF32 presents three scenarios that ostensibly question the emission savings from wind power. None of them makes sense in terms of power system economics and investment.

The scenario: A. Base load generation “Suppose that 10 GW of wind turbines substitute for 10 GW of gas combined cycle plant operating on base load. The average in-feed factor for new gas plants is about 92.6% (95% availability & 2.5% of gross output for internal consumption), so the net output from 10 GW of nameplate capacity would be about 81,100 GWh per year. The typical thermal efficiency for a modern CCGT is 59%, so total CO2 emissions would be 26.9 Mt of CO2 per year. In recent years, the average in-feed factor for UK wind generation has been 27% which gives an average output of 23,650 GWh per year from 10 GW of nominal wind capacity. The remainder would have to be provided by gas OCGT plants operating on a stand-by basis. Under such a regime the thermal efficiency of the plants is unlikely to be higher than 35%, so total CO2 emissions would be 32.1 Mt of CO2 per year. When wind generation displaces efficient base load plants it is correct to claim that more wind capacity leads to increased—not reduced—emissions of CO2. Indeed, the situation is much worse if wind generation displaces nuclear power with minimal CO2 emissions.” Why the scenario makes no sense — Comparing wind and gas on a capacity basis is not sensible. — OCGT would not be used to fill the gap in output. 10 GW of wind turbines are not comparable to 10 GW of gas turbines. This is because the nameplate capacity of wind turbines is simply a function of how much output they will produce at a maximum output that they seldom reach. Indeed, in wind farms around the world the ratio of blade size to generator output will be tailored to specific wind conditions, which will affect the relationship between energy output and nameplate capacity in complex ways. By contrast a gas turbine can be operated at maximum rated capacity for long periods if desired. This doesn’t mean one is “better”, simply that one is optimised to capture wind power and the other to convert fossil fuel into electricity. The only sensible way to compare wind and gas turbines operating is on an equivalent energy basis, comparing costs on a levelised (£/MWh) basis. This means we will need a higher nameplate capacity of wind to produce the same amount of electricity as we would from a given nameplate of gas, it means nothing else and most definitely gives no insight into the amount of “back-up” needed or what form that plant should take. It does not imply—and the notion is utterly false—that we must back-up the wind on a capacity basis.33 It certainly does not imply that the plant used alongside wind must all be low efficiency OCGT. The objective function is to deliver a given quantity of energy, if the objective is to produce 81,100 GWh per year, and wind can provide 23,650 GWh, then why would the remainder have to be provided by OCGT? The remainder would be provided by the most cost effective mix of plant, of which a fraction might indeed be OCGT but the majority would more likely be CCGT, depending on the system size, demand profile and existing power mix. In Britain, if wind displaces CCGT on base-load, then the differential will be almost entirely made up by CCGT, on base-load. The way the “merit” system works is to shift each least cost marginal plant “up” the merit, with the most expensive and least efficient plants used last, and least frequently. This is why Hughes’ contention of a wind-OCGT hybrid running base-load is so absurd. It is utterly irrational to replace base-load or mid merit CCGT with OCGT that sits at the very top end of the merit ranking, and so best serves fast 30 http://www.decc.gov.uk/assets/decc/11/meeting-energy-demand/future-elec-network/5767-understanding-the-balancing- challenge.pdf 31 http://uk.reuters.com/article/2012/03/14/britain-belgium-electricity-idUKL5E8EE5Y020120314 32 http://www.thegwpf.org/wp-content/uploads/2012/08/Hughes-Windpower.pdf 33 This misconception is discussed at length by the author and colleagues in Skea J, Anderson D, Green T, et al, Intermittent renewable generation and maintaining power system reliability, Generation, Transmission & Distribution, 2008, Vol:2, Pages:82–89, ISSN:1751–8695 (http://dx.doi.org/10.1049/iet-gtd:20070023) Authors:Skea J, Anderson D, Green T, Gross R, Heptonstall P, Leach M Energy and Climate Change Committee: Evidence Ev 53

response and peaking functions only. For this reason Hughes scenario is a total fiction, not relevant at all to least cost integration of wind in the 2020s in Britain—or anywhere else.

The scenario B. Mid-merit generation “Using the same capacity figures as in example A above, suppose that wind generation substitutes for mid- merit gas CCGT plants with an in-feed factor of 55% (typical for mid-merit plants). The thermal efficiency would be somewhat lower because of start-up and run-down periods plus periods as spinning reserve. It is reasonable to use a figure of 55% for thermal efficiency yielding total CO2 emissions of 16.0 Mt of CO2 per year. The in-feed factor for wind generation in recent years reflects the fact that wind plants displace base load plants whenever they are available. The appropriate in-feed factor when they displace mid-merit generation will be much lower and will depend on the correlation between availability and demand. It is simplest to assume that in-feed ratio is 14.9%, ie 55% of the base load in-feed factor of 27%. Again, gas OCGT is used as backup. In this scenario total emissions with wind generation are 18.2 Mt of CO2 per year, still higher than with no wind generation.” Why the scenario makes no sense — The of wind does not fall just because it displaces mid-merit plant. — Lower efficiency causes older CCGT to be mid-merit, not the other way around. The first error in the scenario is in conflating cause and effect in terms of which CCGT plant operate at which point in the “merit order”. CGGT plant efficiency lies in a range, with 1990s plant typically around 50% efficient and brand new plant approaching 60% efficient. Older, less efficient plant tends to be used less than the latest and highest efficiency plant as its fuel costs are higher. Mid-merit plant is likely to be operating at 50% efficiency or below, if it is load following extensively. This is a trivial assertion compared to the one that follows. Hughes assumes that 45% of the energy available from wind turbines will be wasted because it occurs at an inconvenient moment compared to a “mid-merit” CCGT. Again, this is a silly and economically inefficient misrepresentation. It suggests in particular that zero marginal cost wind would be rejected from the system in favour of a variety of fuel burning plants, with higher marginal costs whether on baseload, in mid-merit or (potentially as the simplification is so crude) those on peaking/high merit duty. As with the first scenario, Hughes is also assuming that OCGT would be used exclusively alongside the wind plant in favour of CCGT, again for reasons that are not possible to explain because it is not an economically rational way to operate.

Scenario C. Peak load generation “There is little to say when wind generation displaces peak load generation from gas OCGT used in the current system, since there is no difference between the efficiency and emissions for regular peak load plants and those used as backup for wind generation. Hence, there will be a reduction in CO2 emissions equal to the amount associated with the gas generation that is displaced.” Why the scenario makes no sense

For reasons already explained this scenario, though less misleading in terms of CO2 emissions, is just as strange. It would appear to assume that wind is only allowed onto the system if it coincides with peak demands. Are we to assume that at all levels of demand below this wind is constrained off, in favour of plant with higher marginal costs and higher CO2 emissions? This can only be described as a strange Alice in Wonderland inversion of economic efficiency and good sense.

Annex 2 SCENARIOS TO ILLUSTRATE EFFICIENT OPERATION WITH AND WITHOUT WIND POWER The demand for electricity varies over time and it must be generated (or taken from expensive storage devices) at the moment it is consumed. This means that some power stations will have to run for most of the year, meeting the base load demand, while other peaking stations are only needed at times of high demand. The electricity markets in Great Britain allow generators to choose when to run their plants, but the economic incentives are clear. Given the mix of stations currently available, it should be obvious that the stations with relatively low variable costs should be used as much as possible to meet the base load demands, while those with high variable costs should only be used when all the available cheaper stations are already in use. Figure 1 shows what happened during the first week of November 2011, with data taken from National Grid. At the bottom of the graph, nuclear power stations have the lowest variable costs and run continuously whenever they are technically available.34 The next area in the graph shows the generation by CCGT stations burning gas, which was also maintained at a high level over the week. The dark area above the CCGT stations represents the generation from coal-fired stations, which varies much more over the period. This suggests that this was a period when the prices of coal, gas and carbon permits were such that it was more expensive (in terms of variable costs) to generate electricity from a coal-fired station than from a CCGT. The coal-fired 34 The total costs of building and decommissioning nuclear facilities may be very high, but this does not affect whether it is sensible to use a station which has already been started up. Ev 54 Energy and Climate Change Committee: Evidence

stations accordingly reduce their output significantly overnight, and increase it once demand rises again the next day. Note that the CCGT stations also reduce output overnight. This allows the coal-fired stations to continue running at a low load until the morning, rather than having to turn off and re-start the next day. Starting a coal- fired station is expensive, and turning it off and on again too quickly reduces the station’s life. A possible analogy is that it rarely makes sense to turn off a car engine for a short delay at a traffic light. The top bands in Figure 1 show imports from France and The Netherlands and a small amount of generation from oil-fired power stations (grouped together as “other”)—cheap power in those countries allowed the UK to import for much of this particular week, even when our demand was low. Output from hydro-electric stations (both the conventional stations in Scotland, and the pumped storage stations in Scotland and Wales) was concentrated at times of high demand. The graph also shows a small amount of wind output, which comes from the larger wind farms which are connected to the national transmission system (rather than low voltage distribution systems).

Fig. 1 OUTPUT BY POWER STATIONS IN THE GB SYSTEM, NOVEMBER 2011 (NATIONAL GRID)

These power stations were able to increase and decrease output very rapidly in the early morning and in the evening, meeting significant changes in the level of demand. Some of this demand may have been unanticipated, and the system controllers employed by National Grid had to buy power at short notice to ensure that generation was actually equal to demand. The system controllers also made sure that a number of stations were running with spare capacity, able to respond instantly if there was a fault at another plant, and that some were available to start at short notice if needed. All of these balancing costs are collected by National Grid and (in due course) paid by consumers. Figure 2 shows a similar picture, but based on the authors’ simulation rather than history. It uses an economic-engineering model presented at the British Institute for Energy Economics conference, September 2012. The model selects the cheapest combination of plants able to meet the demand for electricity and for reserve capacity, optimising over the year. This means that it will reduce output overnight from plants with relatively low variable costs if this allows other stations to avoid the cost of shutting down and starting up the next morning, just as shown in Figure 1. The model is calibrated for a possible level of demand in 2020, some 350 TWh of output per year (including losses in the transmission and distribution system). Hourly demands from 2010 have been scaled up to give this annual total. The demands have been matched with wind speed data from the same hours to simulate the output from 7 GW of wind turbines spread around Great Britain—roughly the current amount of wind capacity. The model assumes that there will be 11 GW of nuclear capacity (current stock, minus some retirements, plus some new build), 12 GW of existing coal capacity and 4 GW of existing hydro (including pumped storage). The Energy and Climate Change Committee: Evidence Ev 55

model optimises the number of CCGT and OCGT stations to ensure that demand (and reserve requirements) can be met, choosing the combination that best minimises capacity costs and running costs.

Fig. 2

OPTIMAL DISPATCH FOR A SYSTEM WITH 7 GW OF WIND CAPACITY (CALCULATIONS FROM THE MODEL REPORTED BY STAFFELL AND GREEN, BIEE CONFERENCE 2012)

Figure 2 shows a broadly similar pattern to Figure 1, except that there is less coal-fired plant, as some is due to retire before 2016. Because the older CCGT stations are expected to have higher variable costs than the coal-fired stations (using DECC’s central predictions for fuel and carbon prices), they are shown separately from the low-cost new stations. The model mainly chooses to build CCGT stations, and rarely runs OCGT stations—their high fuel costs offset the reduction in capital costs that they offer. The OCGT stations only provide noticeable amounts of output in the early evening of the first, third and fourth days of the week we model (based on demand and wind conditions for the week commencing 11 January 2010).

Figure 3 repeats the exercise using the same demand and wind speed data, but with 30 GW of wind capacity. The wind output (shown in white) is noticeably greater, leading to bigger variations in the demand placed on the thermal power stations—which they are still able to meet. Comparing Figure 2 and Figure 3, it is clear that the extra wind output mostly displaces energy from the older CCGT stations, the coal stations and, overnight between the fifth and sixth days, the newer CCGT stations. Indeed, there is so much wind at that time of (relatively) low demand that it makes sense to spill a small amount of wind energy (shown in a medium shade) to allow more coal stations to continue running through the night at minimum load. The amount of wind output spilled is tiny compared to the amount produced during the week. The amount of energy produced by OCGT stations is also tiny, and less than in the simulations with 7 GW of wind. Ev 56 Energy and Climate Change Committee: Evidence

Fig. 3

OPTIMAL DESPATCH WITH A SYSTEM WITH 30 GW OF WIND CAPACITY (CALCULATIONS FROM THE MODEL REPORTED BY STAFFELL AND GREEN, BIEE CONFERENCE 2012)

Over the whole year, roughly 60% of the energy produced by the additional wind capacity (comparing 30 GW and 7 GW) displaces output from CCGT stations, and 40% displaces coal output. There is a small reduction in nuclear output (less than 1% of the wind output) and 0.3% of the wind output has to be spilled. The output from OCGT stations is almost unchanged.

The particular numbers in these simulations depend upon the assumptions made. Different fuel prices could lead to a different pattern of generation; different assumptions about the capital costs of power stations would affect the capacity mix. The simulations do not consider congestion on the transmission lines between Scotland and England, which can lead to wind being spilled (although new transmission lines are being planned to reduce these problems). They do not deal with the unpredictability of wind power (beyond requiring the system operators to keep plant in reserve to respond to this).

The broad conclusions of this work, however, are likely to be robust to a wide range of assumptions. Additional wind output in Great Britain will generally displace energy from coal- and gas-fired power stations in the years to 2020, reducing CO2 emissions, and there will not be a significant change in the use of OCGT plant.

It is clear that in a least-cost scenario, we do not see the massive expansion of OCGT capacity and output that Hughes proposes.

Annex 3

WIND OUTPUT PATTERNS

We commented on the level of output that would be expected from a diversified fleet of wind turbines in Great Britain. National Grid reports the half-hourly output from all the stations that interact directly with its system, either because they are relatively large or they are directly connected to the transmission system—as opposed to smaller wind farms connected to the distribution networks at lower voltages. In practice, this means that a small number of offshore stations and a large number of stations in Scotland (where the transmission system includes lower voltage cables) are included in the data. Figure 4 shows the distribution of outputs over the three years from 2009–11. It shows that very high outputs are quite unusual, but also shows nearly 600 hours a year in which the load factor was 2.5% or less.35 35 Each bar in the figure counts the number of hours in which the load factor was within plus or minus 2.5% of its central point. Energy and Climate Change Committee: Evidence Ev 57

Fig. 4 THE DISTRIBUTION OF WIND OUTPUTS ACROSS GREAT BRITAIN. COLLECTED FROM HISTORIC TIBCO DATA (COURTESY OF NATIONAL GRID) 2009–2011.

National Grid’s data are dominated by Scottish wind farms, and it is reasonable to expect that there would be a number of hours in which calm weather north of the border is offset by stronger winds further south. Figure 5 reports the results from a simulation36 that uses hourly wind speed data for 2009–11 from the Meteorological Office (provided through the British Atmospheric Data Service) to estimate the output from a fleet of wind turbines spread across Great Britain, with a few offshore stations, as is currently the case. It shows a broadly similar pattern to Figure 4, except that the number of hours with very low outputs is significantly smaller—if it is calm in one part of the country, it may well be windy elsewhere. There are still an important number of hours in which outputs are very low, however, and our modelling (reported in Annex 2) takes account of the fact that some of the highest electricity demands occur at times of cold, calm, conditions.

36 Staffell, I & Green, R 2012, “Is there still merit in the merit order stack”, BIEE September 2012 Conference Proceedings. Figure 5 is based on data used in that paper; Figure 6 uses the same data as the paper. Ev 58 Energy and Climate Change Committee: Evidence

Fig. 5 SIMULATED DISTRIBUTION OF WIND OUTPUTS ACROSS GREAT BRITAIN, ESTIMATED FROM WIND SPEED DATA FROM 2009–2011, USING THE 2011 MIX OF ONSHORE AND OFFSHORE WIND TURBINES.

Figure 6 is a further simulation, using the same wind speed data but now assuming that far more of the wind stations would be offshore, where wind speeds (and therefore outputs) are higher. Once again, it is broadly similar to the earlier Figures (which helps to validate the model), with a further small reduction in the number of hours of very low load factors. Load factors of between 10% and 50% occur in two-thirds of the hours in the year, and it is still very unlikely that the total output will exceed 80% of installed capacity. This is the data used in the simulations reported in Annex 2.

Fig. 6 SIMULATED DISTRIBUTION OF WIND OUTPUTS ACROSS GREAT BRITAIN, ESTIMATED FROM WIND SPEED DATA FROM 2009–2011, USING THE POTENTIAL 2020 MIX OF ONSHORE AND OFFSHORE WIND TURBINES (11 GW ONSHORE, 19 GW OFFSHORE).

October 2012 Energy and Climate Change Committee: Evidence Ev 59

Written evidence submitted by Renewable UK Introduction 1. Wind power offers huge benefits, including meeting 2020 targets and creating jobs right here in the United Kingdom. RenewableUK as the largest trade association in this sector welcomes the opportunity to respond with this written response. In addition, we are keen to expand upon what we have responded to in this written response by presenting evidence in person on Tuesday 10 July.

What do the latest assessments tell us about the costs of generating electricity from wind power compared to other methods of generating electricity? 2. Onshore wind is the least expensive form of renewable energy that can be produced at scale. In addition, it is without the risk of constant fuel price fluctuation. Since the UK is committed to legally binding 2020 targets, it is imperative onshore wind continues to receive support to increase its volume in the market and thus stabilise prices for consumers while minimising the cost of meting targets. It is worth noting that total wind costs are particularly sensitive to finance costs, arising from wind’s high capital/low marginal cost characteristic. Various pieces of analysis conducted by Arup, Mott MacDonald, and the Committee on Climate Change have correctly identified onshore wind as the most affordable renewable technology at scale in addition to the huge potential of mass wind generation offshore. Offshore wind is currently more expensive, but offers a huge amount of potential without some of the concerns, such as planning, facing onshore wind. Recent work by The Crown Estate affirmed that attaining £100/MWh for offshore wind by 2020 is possible.37 Earlier analysis conducted by UK Energy Research Centre (UKERC) in 2010 predicts that in a good case scenario costs could decrease from £145/MWh to £95/MWh.38

How do the costs of onshore wind compare to offshore wind? 3. Capital costs for offshore wind are around 30–50% higher than onshore, mainly due to foundations and the costs of transporting and installing at sea. This is partially offset by higher energy yields—as much as 30% higher. However, as has happened with onshore, the levelised cost of energy is expected to fall due to technological innovation. In addition, scale and efficiencies can be obtained as more experience is gained. Cost reduction for offshore wind is a huge challenge, but one the industry has recently announced its commitment to deliver with the publication of the Offshore Wind Cost Reduction Task Force Report. In the report, the steps required by industry and Government to reduce costs by 30% are outlined. That would put the levelised cost of offshore wind at £100/MWh by 2020.39 Committee on Climate Change analysis conducted by Mott MacDonald indicates the current levelised costs for onshore wind ranges from £83-£90/MWh compared to £169/MWh for offshore wind.40

What are the costs of building new transmission links to wind farms in remote areas and how are these accounted for in cost assessments of wind power? 4. There is a trade-off between locating any generation source close to the existing grid and seeking more favourable sites further from the existing grid. There is a similar trade-off between locating generation close to the major demand in the South East and the cost and availability of generation sites. These trade-offs are exacerbated for many renewables as resources like wind are generally better the further away from the existing demand and grid. According to the Electricity Network Strategy Group, the total cost of generation-based onshore grid reinforcements in Great Britain to 2020 is around £8.8 billion,41 which connects 23GW of wind in a total of 38.5GW of new generation. There are additional costs for the offshore connections. The total cost of onshore transmission is under negotiation under the price control RIIO-T142 but is likely to be in the order of £30 billion up to 2021 for all works including ENSG investments, and refurbishment of aging assets, most of which were built in the 1960s. 5. The cost to the average domestic customer of transmission is currently 4% of their bill (£17/year) and the Scottish Companies’ RIIO-T1 proposals would increase this by 35p per annum.43 National Grid’s price control has yet to be agreed. The charges to any generator connecting to the transmission network are based on cost reflective pricing. That means that generators pay around 85% of the cost of any local grid extension, be that onshore or offshore. In addition, charges for use of the backbone transmission network reflect north-south flows so that annual transmission charges in the North West of Scotland are £22.05/kW compared to a subsidy, or negative charge, of £-13.35/kW in Central London. Some changes to charges are imminent under Ofgem’s project “TransmiT”. We hope that changes will eventually recognise the shared use of transmission by renewables and fossil fuels, and will treat new HVDC technology in a similar way to existing AC technology; 37 The Crown Estate (TCE). 2012. Offshore Wind Cost Reduction Pathways Study. 38 UK Energy Research Centre (UKERC), 2010. Great Expectations: The cost of offshore wind in UK waters—understanding the past and projecting the future. 39 Offshore Wind Cost Reduction Task Force, 2012. Offshore Wind Cost Reduction Task Force Report. 40 Committee on Climate Change (CCC), 2011. Costs of low-carbon generation technologies. 41 Electricity Networks Strategy Group (ENSG), 2012. Our Electricity Transmission Network: A Vision for 2020. 42 Ofgem, 2012. RIIO-T1 (first transmission price control review under the RIIO model). 43 Ofgem, 2012. Initial Proposals for Transmission Price Control SPT and SHETL for the next transmission price control—Impact Assessment. Ev 60 Energy and Climate Change Committee: Evidence

these changes should limit cost increases for renewables in the north of GB. From this it should be clear that wind power pays its full share of the cost of the network, including the investment to extend the grid to areas of renewable resource. Given that wind is the first major new resource to be developed since the privatisation of the electricity industry in the UK, it is the first technology to have to pay for grid extension rather than have the cost socialised across all users.

How much support does wind power receive compared with other forms of renewable energy?

6. Currently Onshore wind receives 1ROC/MWh and offshore wind 2ROC/MWh. The most recent Renewables Obligation statistics indicate that in 2010–11 onshore wind received 7,678,727 ROCS and offshore wind received 5,016,832 respectively, together accounting for just over half of the total ROCs issued in the year.44 A total of 12,189,049 ROCs were issued to other technologies such as biomass, landfill gas and hydro. With the value of a ROC being £51.34 (the buyout price of £36.99 plus recycle value of £14.35), overall the RO cost £1.3 billion in 2010–11, delivering 23.2TWh, around 7% of total electricity demand.45 Therefore, onshore wind received £400 million in 2010–11 and offshore wind £260 million.

7. The development of onshore wind and the support provided under the RO has provided a platform for developers to move to other technologies such as offshore wind and marine. The UK is currently pressing ahead with construction of the Round 2 Offshore developments. Costs for offshore wind are considerably higher than onshore wind given the challenges it presents—offshore construction environment, environmental considerations, offshore grid infrastructure—resulting in the current requirement for 2ROC/MWh. The Round 3 programme will bring further challenges in terms of the scale and location of construction further offshore in deeper waters. We acknowledge that there are cheaper renewable technologies, requiring lower levels of support than onshore wind, however, they have either reached their full potential (eg landfill gas) or face other challenges. For example, the co-firing of biomass depends on station running regimes and biomass availability, preventing significant scale of deployment.

What lessons can be learned from other countries?

8. The cost basis in the UK is considerably different compared to other nations, making it difficult to draw strong comparisons between it and other European countries. We do know that strong support attracts manufacturing and that uncertainty undermines confidence, pushing up costs. The UK should aim to attain similar balancing, network and planning costs to other countries. For instance, other countries tend to have much lower costs of short term balancing because the UK’s current market system makes the provision of balancing and administrative services expensive. Furthermore, there are additional development risks for offshore wind in the UK, where sites are allocated without consent (unlike, for instance in Denmark), and without grid connections paid for (unlike in Germany).

9. RenewableUK has begun investigating the possible existence in the UK of the Merit Order Effect (MOE), where high levels of wind generation result in lower market prices for electricity. The MOE exists because wind generation displaces power from generators with higher marginal costs. The MOE has been identified in countries such as Germany and Denmark (areas of high wind penetration) where it has often reduced the wholesale price of energy for consumers. We have seen harsh cuts in renewable support and retrospective action taken in other countries. These actions send messages to investors not just in renewables but also wider industry in relation to policy intervention. As we move to a new support mechanism under Electricity Market Reform it is essential that investors have confidence in UK policy.

What methods could be used to make onshore wind more acceptable to communities that host them?

10. It is important to note the huge benefits of wind development, such as providing direct and supply chain employment to thousands across the UK. Analysis shows that the vast majority of jobs created in development and operations and maintenance are within the region of wind farms. In addition to jobs, other benefits such as community ownership, including investment in wind energy projects, and community benefit funds supporting local infrastructure projects and facilities can be achieved. Community ownership involves wind farms generating income for local shareholders, which can help to improve community cohesion and provide funds to invest in further area economic and social development. There are a wide range of models for community benefit funding, where the owner of the wind farm distributes funding to be used for community 44 Department of Energy and Climate Change (DECC), 2012. Renewables Obligation: statistics. 45 Ofgem, 2012. Renewables Obligation annual report 2010–11. 46 RenewableUK and DECC, 2012. Onshore Wind: Direct & Wider Economic Impacts. Energy and Climate Change Committee: Evidence Ev 61

projects. Community benefit funds improve quality of life by supporting investment in community projects, and create jobs relating to the administration of the income and as a result of the projects themselves.47 June 2012

Written evidence submitted by RES

1 RES is one of the leading renewable energy developers in the UK, and has developed over 6.5GWs of onshore wind projects globally, in addition to offshore, biomass and PV. RES is presenting on behalf of Fred.Olsen Renewables and Infinis.

1.1 Onshore wind is the most cost-effective low carbon generation deployable on a large scale. At 0.9 ROCs, with each ROC valued at £42.37/MWh,1 given that wind with a low short run marginal cost will 2,3 displace either coal or gas generation the costs per tonne of CO2 saved is between £53/tCO2 and £67/tCO2 for displacing coal and natural gas respectively. For offshore wind the equivalent costs are £117.8/tCO2 and £149.8/tCO2. In comparison: 1.1.1 Switching to Gas. As gas (and wind) is cheaper as new generating capacity than new coal plant with CCS at current market prices, it gives an emissions saving and a financial benefit. But, if market logic alone dictates investment then all new generation would be gas CCGT, creating an electricity industry that is dependent on a single source of energy and as a result, very exposed to supply side shocks4 price volatility and increasing gas prices (which have trebled over the last ten years5). By investing in low carbon generation now, we can mitigate these risks. 1.1.2 Switching to Nuclear. With current uncertainty on nuclear costs and rates of return required to bring forward investors, we believe current estimates significantly understate the outturn cost for a private company. 1.1.3 Energy Efficiency. Estimates for abatement outside of the energy sector6 suggests that approximately 80mtCO2 could be saved at no cost; 40mtCO2/yr could be saved at cost up to £50/tCO2; 30mtCO2/ yr at a cost up to £150/tCO2 and a further 50mtCO2/yr at a cost less than £250/tCO2. However, the fact that there is a large potential for cost effective measures highlights the importance of non- economic barriers and potential difficulty realising these savings.

1.2 Measuring the cost effectiveness of carbon saving involves high-level approximation for energy- efficiency and renewable measures and will depend on the end user’s behaviour patterns, system interactions, income and substitution effects. However, this does not detract from the high level lessons: 1) there is a large potential for cost-effective savings which appear difficult to reach; 2) the costs of energy saving increases sharply after the first tranche; 3) to achieve the 4th carbon budget targets needs to be addressed; 4) gas, under current prices, has associated savings but risks over-dependency and future price uncertainty 5) onshore wind is mid-way along the curve and is one of the cheapest technologies to diversify the energy mix, cut emissions, and can be deployed at scale; 6) Offshore wind is more expensive, but has the potential for cost reductions, and broader economic and industrial benefits.

1.3 Some reports claim that wind turbines emit more CO2 in their production than they save through generation. This is incorrect. A review of the ratio of energy delivered to energy cost for 119 turbines7 concluded that the ratio was between 25:1 and 20:1; a V80–2.0MW turbine is expected to generate 28 times 8 more energy than consumed over its life cycle. Other reports claim that wind power can increase CO2 emissions,9,10,11 however, the underlying reports base their results on overly simplistic that are not representative of complex electricity systems.12,13 National Grid’s14 forecasts build out of wind is one factor contributing to the reduction in the carbon intensity of electricity falling from 500g CO2/kWh at present to 222g CO2/kWh in 2020 and 48g CO2/kWh in 2030. This finding was also replicated by Poyry’s study into intermittency.15

2 Levelised costs from Arup and Mott McDonald shows that onshore wind is the cheapest generation technology at £90-£94/MWh apart from gas without CCS at £77-£80/MWh. Levelised costs provide a cost comparison between technologies. Of the reports shown the Arup report is the most widely reviewed and scrutinised for renewables. £/MWh at consistent 10% discount rate ARUP16 Mott Parsons MacDonald17 Brinckerhoff18 Low Carbon & Low Uncertainty Onshore > 5MW 90.2 93.9 - Good understanding of capital costs Onshore < 5MW 104.9 - Good understanding of fuel Cost Offshore wind Round 2 121.6 160.9 Solar 314.3 Low Carbon & High Uncertainty Dedicated Biomass 127.6 116.0 - Either uncertain capital costs < 50MW - Or uncertain fuel Cost 47 RenewableUK and DECC, 2012. Onshore Wind: Direct & Wider Economic Impacts. Ev 62 Energy and Climate Change Committee: Evidence

£/MWh at consistent 10% discount rate ARUP16 Mott Parsons MacDonald17 Brinckerhoff18 - Dedicated Biomass 144.6 93.2 > 50MW - Offshore Wind R3 147.5 190.5 - Nuclear 99.0 74.1*19 Low Carbon & Very High Uncertainty Coal ASC+ CCS 142.1 104.8 - Uncertain capital costs Coal IGCC + CCS 147.6 134.8 - And Uncertain Fuel Costs Gas CCGT + CCS 112.5 104.8 High carbon & High Uncertainty Coal ASC 104.5 95.4 - Good understanding of capital costs Coal IGCC 134.6 126.2 - Uncertain fuel Cost Gas (CCGT) 80.3 76.6

2.1 To be clear, these costs cover: development, construction and grid connection costs (to the local substation), and annual operating costs which include payments to Network Operators to cover broader system costs. Some detractors use this complexity (or simply don’t understand) to make exaggerated claims of additional costs that have actually already been counted. Civitas9 makes bogus claims of an additional £60/ MWh to be added onto the cost of wind due to unallocated costs in a reference that traces back through a Renewable Energy Foundation Paper20 to a paper by Gibson21 that allocates additional “Extra System Operation Costs”, “Capital Charges for extra Planning Reserve”, and “Total Capital Charges for Required Transmission”. The authors “overlook” the fact that the Parson’s Brinkerhoff Report22 used to define the first Gibson Cost “Extra System Operation Costs” already includes the two other Gibson Costs.23 3 Offshore wind is approximately £30/MWh more expensive than onshore wind for a Round 2 project. This figure does not take into account the work being undertaken by the Offshore Wind Cost Reduction Task Force24 which sets out key actions to cut the cost of generating offshore electricity by 30% to £100 per MWh by 2020. This is a challenging target, our ability to achieve it and realise the wider benefits depends on investor confidence in the Government’s renewable energy policy. 4.1 The direct costs of building new transmission infrastructure is directly taken into account in the cost assessment of onshore wind, there are low network costs that are currently not included. Reports such as ARUP include the majority of grid related costs; the cost of onsite infrastructure and site connections to local substations are included in the capital cost estimate, whilst wider transmission development and maintenance costs in the local distribution25 or national transmission network26 are recovered through annual operating costs. There are costs associated with increased wind penetration that are not directly attributed to the site and are therefore outside the scope of these cost assessments, including; 4.1.1 Balancing Costs. Large windfarms directly incur balancing use of system charges of around £2/ MWh. This may be realised as a “benefit” for smaller onshore wind generators that are embedded in the network. 4.1.2 Transmission Use of System Charges Passed onto the Consumer. Under current charging methodology, transmission company allowable revenues are recovered from generator and consumers on a 27% to 73% split. National Grid’s business plan27 allocates an additional charge to consumers of £10 per household in 2027 (approximately £3/MWh) due to factors including the connection of renewable and conventional generation, smart grid roll-out, new systems, and asset replacement (often dating back to the 1950’s). 4.1.3 Constraint Payments.28 Payments to wind generation spiked from £176,000 in 2010 to £12.7 million in 2011 (compared with over £700 million balancing services spend as a whole) in a one-off spike due to a number of largely unrelated issues combined to create unique circumstances.29 This is unlikely to be repeated with the implementation of improved practices for wind farm owners, National Grid’s improved operating procedures and new transmission investment. 4.2 Complex grid charging arrangements enables misinformation to be propagated through un-reviewed papers presented as fact. The second Gibson Cost21 that fed into Civitas’s9 additional £60/MWh was transmission connection. Gibson’s explanation in summary is;30 “The extra cost for Transmission ….is based on the latest costs for the Beauly-Denny Line …..This would result in an additional £15.5/MWh of levelised cost…. The distance from Denny to this notional point is some four times the distance …. A large assumption is made by simply doubling the levelised cost of Beauly-Denny to £31/MWhr.” This is a “large assumption” as it is double counting costs already included in the levelised cost calculation, assumes all windfarms are in North Scotland, that a large electrical infrastructure project is a representative of cost, and ignores the existing grid Infrastructure. 5 Detailed analysis suggests that the current cost associated with providing back up capacity is around £2/MWh and this could increase to £4/MWh in 2020. More back-up capacity is required regardless due to new nuclear. The cost of backup can be divided into the cost of frequency response,31 short term operating reserve requirement32 and longer term capacity adequacy. The impacts of increasing wind generation on the first two are addressed by National Grid,33 who estimate that short term operating reserve requirements will increase from £2.1/MWh now to £4.06/MWh in 2021,34 due to increases in both wind and nuclear capacity. Longer term capacity adequacy is additional to this and the Government’s Impact Assessment Energy and Climate Change Committee: Evidence Ev 63

estimated at a cost £300-£350m/yr in 2025.35 If this was all directly attributed to wind it would indicate a cost in 2025 of £3.6/MWh. Combining these costs gives current reserve costs of £2.1/MWh, increasing to £4/MWh in 2020 and potentially £7.6/MWh in 2025. 5.1 Detractors of wind generation, misrepresent the back-up capacity, citing the fact that wind does not generate at full load 100% of the time. Civitas reported a third Gibson Cost of £24/MWh based on a MW of wind needing to be matched with a corresponding MWs of dispatchable plant (or close to it). This logic is flawed. No plant can be relied upon to generate 100% and wind plant’s investment decision is the based on a capacity factor is consistently around 30%, not 100%. 6 Onshore wind receives support of £42/MWh (£38/MWh after banding) whilst offshore receives £85/ MWh which will be reduced to £76/MWh in 2016–17. This is based on the current allocation of ROCs to each technology. The only technologies that receive less support than onshore wind are landfill gas (0.25 ROCs), sewage gas (0.5 ROCs) and co-firing (0.5 ROCs). However the potential to expand the renewable capacity from these sectors is limited. 7 Consumers currently pay £4.6/hhld for onshore wind and £3.06/hhld for offshore, a total of £7.7/ hhld.36 This total cost of support for all renewables is expected to increase from £20/hhld to around £95/hhld in 202037 Organisations such as Policy Exchange have multiplied this to give a cost of £400/hhld38 in 2020 through some dubious economics.39 Between 2004 and 2010 rising gas prices has increased consumer bills by £29040 applying Policy Exchange’s logic this should have been an increase of over £830/hhld. 8 If common practice in Sweden and the USA was adopted in the UK then the costs would be reduced, common practice includes a simpler planning process, higher hub-heights and larger rotor diameters.

9 We actively engage with local communities at all stages of the planning, construction and operation processes for our wind farms. In addition to our existing Community Benefit Funds we are committed to exploring new and innovative ways in which our wind farms can bring tangible benefits to the local communities hosting them.

References 1 E-ROC Auctions, http://www.e-roc.co.uk/trackrecord.htm. The average price achieved per ROC at the monthly e-ROC auction on the 24th May was £42.37/MWh. 2 DEFRA, Greenhouse gas conversion factors for company reporting, http://www.defra.gov.uk/publications/ files/pb13773-ghg-conversionfactors-2012.pdf, 2012 Guidelines. Using the grid rolling average direct greenhouse gas emission factor for electricity before transmission losses of 0.482kgCO2/KWh (Annex 3, Table 3a) and Natural Gas and Coal have emission factor of 0.205 and 0.3436 on a Net Calorific Value (Annex 1, Table 1d, total direct greenhouse gas column). A very conservative approach which does not take into account the existing low carbon generation, the cost per tonne of carbon saved is £87.9/MWh. 3 Digest of UK Energy Statistics (DUKES) 2011, http://www.decc.gov.uk/en/content/cms/statistics/ publications/dukes/dukes.aspx, Table 5.10 Plant Loads, Demand and Efficiency.—This gives an average generating efficiency of 47.6% and 36.1% for coal and natural gas CCGT in 2010. This is conservative as it is likely to be older less efficient plant that is displaced. 4 The Impact of Import Dependency and Wind Generation on UK Gas Demand and Security of Supply in 2025, Howard Rogers, Oxford Institute for Energy Studies, August 2011, http://www.oxfordenergy.org/wpcms/ wp-content/uploads/2011/08/NG-54.pdf. 5 DECC Energy Price Statistics, http://www.decc.gov.uk/en/content/cms/statistics/energy_stats/prices/ prices.aspx, Retail prices: “DECC—Monthly Tables—Retail Prices Index—Fuel Components—April 2012”- This shows an index of 224.2 for the fourth quarter of 2011 and is compared with an index of 72.5 for the fourth quarter of 2000 (a multiple of 3.05); or an index of 75.8 for the fourth quarter of year 2001 (a multiple of 2.96). Industrial prices: “DECC—Quarterly Tables—Prices of fuels purchased by manufacturing industry p- kwh -March 2012”—For the average industrial customer, gas prices in the fourth quarter of 2011 were 2.330p per kWh , compared to a price in quarter four of year 2000—of 0.764p per kWh—a multiple of 3.05. For the fourth quarter of 2011 the price was 0.834p per kWh—a multiple of 2.79. 6 DECC, Fourth Carbon Budget, Dec 2011, (Annex B, Chart B8, Pg 165). http://www.decc.gov.uk/assets/decc/ 11/tackling-climate-change/carbon-plan/3749-carbon-plan-annex-b-dec-2011.pdf 7 Renewable Energy, Volume 35, Issue 1, January 2010, Meta-analysis of net energy return for wind power systems, Ida Kubiszewski, Cutler J Cleveland and Peter K Endres, http://www.sciencedirect.com/science/ article/pii/S096014810900055X. 8 Life Cycle Assessment of Electricity Production from a V80–2.0 mw Gridstreamer Wind Plant, Vestas, Peter Garrett & Klaus Rønde, Decemebr 2011, http://www.vestas.com/en/about-vestas/sustainability/sustainable- products/life-cycle-assessment/available-life-cycle-assesments.aspx. Ev 64 Energy and Climate Change Committee: Evidence

9 Wind power is expensive and ineffective at cutting CO2 say Civitas, Telegraph, 2012, http://www.telegraph.co.uk/earth/earthnews/9000760/Wind-power-is-expensive-and-ineffective-at-cutting- CO2-say-Civitas.html 10 Policy Exchange (2011) Climate Policy—Time for Plan B, http://www.policyexchange.org.uk/images/ publications/climate%20change%20policy%20-%20time%20for%20plan%20b%20-%20jun%2011.pdf. 11 Why is Wind Power so Expensive, An Economic Analysis, Gordon Hughes, The Global Warming Policy Foundation, 2012, http://thegwpf.org/images/stories/gwpf-reports/hughes-windpower.pdf.

12 C (Kees) le Pair, “Electricity in the Netherlands: wind turbines increase fossil fuel consumption & CO2 emissions”, October 2011, http://www.clepair.net/windSchiphol.html. In the paper the main model used to generate the findings are based on a simplified system with one large wind farm, one large gas fired CCGT and an OCGT. The lack of smaller units which are geographically dispersed magnifies the volatility in wind output, the single CCGT units exaggerates the impact of ramping, this then further exaggerated by the lack of any interconnection, whilst the lack of demand variation overlooks the reserves that are required to maintain system stability under normal conditions. 13 Joskow, PL (2010) “Comparing the costs of intermittent and dispatchable electricity generating technologies”, Working Paper 10–013, Center for Energy and Environmental Policy Research, MIT. His critique of the levelised cost methodology is primarily based on the time of day of generation in the context on the UK wind output is typically correlated with peak periods, which is a beneficial impact. 14 National Grid, Gone Green 2011 Key Facts and Figures—Gone Green Scenario with wind installed increasing to 26 GW in 2020 and 47 GW in 2030 (Page 2, electricity generation and carbon intensity), http://www.nationalgrid.com/NR/rdonlyres/F6FA7970–5FEA-4918–8EE2–2A8E6B9626FF/50214/10312_1_ NG_Futureenergyscenarios_factsheet_V2_st3.pdf. 15 The implications of significant wind build out on load factors and therefore the returns to investment of thermal plant was highlighted in the Poyry study on the Implications of Intermittency which RES participated in as a core sponsor. . 16 DECC, Review of Generation Costs and Deployment Potential of Renewable Electricity Technologies in the UK, Arup (2011), http://www.decc.gov.uk/assets/decc/11/consultation/ro-banding/3237-cons-ro-banding- arup-report.pdf. 17 Mott MacDonald (June 2010) “UK Electricity Generation Costs Update”, http://www.decc.gov.uk/assets/ decc/statistics/projections/71-uk-electricity-generation-costs-update-.pdf. 18 Parsons Brinckerhoff (August 2011), Electricity Generation Cost Model—2011 Update, http://www.pbworld.com/pdfs/regional/uk_europe/decc_2153-electricity-generation-cost-model-2011.pdf. 19 PB Nuclear costs have significantly more favourable assumptions compared to the ARUP report—higher efficiency, availability and load factors on the operating parameters and lower capital cost and operating costs. Analyst reports from Citigroup suggest that levelised costs could be doubled from these levels. http://uk.reuters.com/article/2012/05/08/uk-nuclear-britain-edf-idUKBRE8470XC20120508 20 Renewable Energy Foundation “Energy Policy and Consumer Hardship” (2011), http://www.ref.org.uk/ attachments/article/243/REF%20on%20Fuel%20Poverty.pdf. 21 Colin Gibson, A probabilistic Approach to Levelised Cost Calculations For Various Types of Electricity Generation, (2011) 22 Parsons Brinkerhoff, Powering the Nation, A Review of the Costs of Generating Electricity, (2006), http://www.pbworld.com/pdfs/regional/uk_europe/pb_ptn_report2006.pdf. 23 This was debated at length when we challenged these figures on the Full-Fact Website. Civitas’s response was that it was acceptable to use them because they were draft and there was no better information available. When we challenged them on this and presented better and more up-to-date evidence they were unable to respond http://fullfact.org/blog/figures_civitas_wind_power_report_res-3251 and http://fullfact.org/blog/ figures_civitas_wind_power_report_res-3290 . 24 Offshore Wind Cost Reduction Task Force Report, June 2012, http://www.decc.gov.uk/assets/decc/11/ meeting-energy-demand/wind/5584-offshore-wind-cost-reduction-task-force-report.pdf. 25 The Local Distribution System upgrades beyond the local substation are covered by GDUoS charges and an upfront capital cost contribution. 26 The Transmission distribution charges vary by location, from £21.9/KW for areas furthest from demand to negative value for sites connected in central London (subject to Ofgem’s review of transmission charging, Project TransmiT). As an approximation, the higher windspeeds to the north correlate with the higher connection charges. 27 National Grid Electricity Transmission’s RIIO-T1 Business Plan headlines (July 2011). Forecasts that costs charged through to households will increase from £17/hhld/yr to £27/hhld/yr (Page 12). Energy and Climate Change Committee: Evidence Ev 65

http://www.nationalgrid.com/NR/rdonlyres/A7691393–6DCB-4849–8C0D-DCACEB2004A9/48221/NGET_ Headlines.pdf. 28 Hansard, 17th Jan 2012, Charles Hendry Response to Glyn Davies, http://www.publications.parliament.uk/ pa/cm201212/cmhansrd/cm120117/text/120117w0003.htm 29 These constraint payments were caused by a particular period of high wind output, which coincided with the outage of significant specific transmission assets. Wind operators had systems in place to respond, but due to not having called on them before these were not appropriately calibrated for up-to-date market conditions. The Wind Industry has now responded to ensure appropriate procedures are in place and become more engaged with balancing market participation. Furthermore, National Grid’s development of forecasting and system operation practices together with new transmission investment reduces the need for balancing market actions associated with extraordinary wind and transmission outage events. 30 Colin Gibson, , (2011), The Institution of Engineers and Shipbuilders in Scotland (IESIS). Version 22.10.2011 Pages 5–6, section 3.1.8. “The extra cost for Transmission to connect generation in the north of Scotland to the main load centres in the south of England is based on the latest costs for the Beauly-Denny line of some £600 million. The Public Inquiry was based on 2100 MW of generation in the North West. This would result in an additional £15.5/MWh of levelised cost. However this power has to be transferred to a notional point on the transmission system just north of London and aggravates existing limitations to the general flow or power north to south. The distance from Denny to this notional point is some four times the distance from Beauly to Denny. A large assumption is made by simply doubling the levelised cost of Beauly- Denny to £31/MWhr.” 31 National Grid, Operating the Electricity Transmission Networks in 2020, pg 40 (June 2011) Para 7.11— Frequency response is short term adjustments to control for the second-by-second balance between generation and demand. http://www.nationalgrid.com/NR/rdonlyres/DF928C19–9210–4629-AB78-BBAA7AD8B89D/ 47178/Operatingin2020_finalversion0806_final.pdf 32 National Grid, Operating the Electricity Transmission Networks in 2020, pg 21 (June 2011) Short reserve (operating reserve) is capacity held to manage the uncertainties between generation output and demand fluctuation. 33 National Grid, Operating the Electricity Transmission Networks in 2020, Table on pg 74 (June 2011) 34 National Grid don’t come to a firm conclusion with regards frequency response requirements. For short term operating reserves, the cost is increase due to wind’s capacity increasing from 38GWs to 26.7GWs such that Wind’s Reserve Requirement will increase from 0.83 TWh to 5.86 TWh in 2020–21. Expressed as unit of output of wind, the cost is expected to. increase from £2.1/MWh now to £4.06 in 2021. 35 DECC, Electricity Market Reform—Capacity Mechanism, Impact Assessment, December 2011— (Para 5.16—5.17), http://www.decc.gov.uk/assets/decc/11/consultation/cap-mech/3883-capacity-mechanism- consultation-impact-assessment.pdf. 36 OFGEM, Renewables Obligation Annual Report 2010–11, http://www.ofgem.gov.uk/Sustainability/ Environment/RenewablObl/Documents1/Renewables%20Obligation%20Annual%20Report%202010–11.pdf, (2012) this based on the latest figures generated by OFGEM of total cost of the RO of £1.28 billion with approximately 50% awarded to wind. There are then some additional projects commissioned under either NFFO or the small scale Feed-in-Tariffs, however the number of MWs actually consented was relatively small with only 391 MWs constructed under NFFO (UK Renewable Energy Policy Since Privatisation, Michael G Pollitt, January 2010, http://www.eprg.group.cam.ac.uk/wp-content/uploads/2010/01/ PollittCombined2EPRG1002.pdf) and 18.9MWs under FITs (Feed-in Tariff (FIT): Annual report 2010—2011, Ofgem, December 2011, http://www.ofgem.gov.uk/Sustainability/Environment/fits/Documents1/ FITs%20Annual%20Report%202010%202011.pdf). 37 DECC, Estimate Impacts of Energy and Climate Change Policies on Energy Prices and Bills, http://www.decc.gov.uk/assets/decc/11/about-us/economics-social-research/3593-estimated-impacts-of-our- policies-on-energy-prices.pdf, Nov 2011, Appendix Table F2. The total cost of renewables is around £20/hhld of which around half, £10/hhld, is accounted for by wind power. This increases by around £95 by 2020 (RO at £48 + FiTs at 6 + EMR at £41). This compares with whilst the Climate Change Committee estimate an additional £110/household in 2020 (Committee on Climate Change, Household Energy Bills—Impacts of meeting carbon Budgets, http://downloads.theccc.org.uk.s3.amazonaws.com/Household%20Energy%20Bills/ CCC_Energy%20Note%20Bill_bookmarked_1.pdf, (Dec 2011) 38 The Policy Exchange (2012) “The Full Cost to Households of Renewable Energy Policies.” 18 January 2012. Author: Simon Less, http://www.policyexchange.org.uk/images/publications/ the%20full%20cost%20to%20households%20of%20renewable%20energy%20policies%20-%20jan%2012.pdf (Page 2 and 6). Policy Exchange calculate the additional cost of £400/hhld by 2020, by taking the DECC estimates of £100/hhld and adding three additional costs, £185 passed through from additional costs of energy that businesses pay as a result of RO/EMR, additional grid costs of £75/hhld, and additional RHI cost of £55/ yr. The additional grid costs has already been discussed, and the RHI is outside of the scope of this call for evidence. The additional £185 cost pass is calculated by arguing that the average UK domestic consumer Ev 66 Energy and Climate Change Committee: Evidence

consumes 30% of the UK electricity therefore the total cost per household is £333. Of that £233 that is charged to the UK business Policy Exchange then estimate that 80% of the cost is passed back to the domestic consumer again to give you the £185 additional cost. 39 Nonsense on stilts? Investigating the discourse around policies and consumer bills: A case study on the Policy Exchange research note on the full cost of renewable energy policy, ICEPT (Imperial College Centre for Energy Policy and Technology) Discussion Paper, February 2012 40 Committee on Climate Change, Household Energy Bills—Impacts of meeting carbon Budgets, http://downloads.theccc.org.uk.s3.amazonaws.com/Household%20Energy%20Bills/CCC_ Energy%20Note%20Bill_bookmarked_1.pdf, (Dec 2011). The additional calculation is our own based on CCC’s figures and applying Policy Exchange’s logic. The impact of rising gas prices on household electricity bills is £290/hhld, therefore the total cost per household equivalent is 290/0.3 = 966; so the cost to business incurred per household equivalent is 966 *0.7=676. Of this 80% is recirculated in the economy and passed back to households: 676*0.8=540; As a result the total cost of gas increases to the UK household from 2004 is £290+£540 which equals 830/Hhld June 2012

Written evidence submitted by Vestas Wind Systems What do cost benefit analyses tell us about onshore and offshore wind compared with other measures to cut carbon? Cost benefit analysis can explore the relative benefits derived from wind compared to other forms of power. A cost benefit analysis looking at the whole system cost for wind would need to include the following costs capital costs, operating costs and any back up costs required over existing levels. An analysis would also need to include the following benefits; output of electricity, contribution towards energy independence and security, social cost of carbon avoided, community benefits generated, value of reduced long term power price volatility, value of avoided health impacts. Some costs such as the cost of developing new transmission lines would need to take account of the comparative benefit that existing capacity has realised from the historic design of the transmission system. Analyses looking at total economy impacts would also need to include the benefits of job creation and investment and the impact this has on local communities.

What do the latest assessments tell us about the costs of generating electricity from wind power compared to other methods of generating electricity? There are various assessments of the financial cost of generating electricity from wind compared to other methods. The costs of onshore wind are relatively clear and transparent. There are databases that track published project costs of various onshore wind projects, for example Bloomberg gathers such evidence. There is also substantial potential for the cost of offshore wind to fall, and the industry is working together to ensure that cost reductions are realised. The Cost Reduction Task Force and Crown Estate’s Cost Reduction Pathways reports provide useful analysis of how costs can fall going forward. It is extremely difficult to accurately assess the financial cost of new nuclear stations due to the huge uncertainty over their capital costs, construction time and operating, insurance and decommissioning costs. It is also very difficult to accurately predict future costs of gas generation. Whilst the cost of new gas stations is relatively clear the operating costs are much more difficult to predict. There is significant uncertainty over imported gas prices and future carbon prices both of which impact the levelised cost of gas generation.

How do the costs of onshore wind compare to offshore wind? The cost of onshore wind is considerably lower than the current cost of offshore wind. There is, however, good reason to believe that the cost difference will fall in future. Arup estimated the cost of onshore wind to be between £72–105/MWh; Vestas broadly agrees with this. The primary factors in the cost are the wind speed, the blade span, hub height and the MW rating of the turbine used. In general the greater the wind speed, the higher the hub height, the larger the turbine and the longer the blades, the lower the cost would tend to be. Other cost factors include the cost of community benefits, the ease of transporting turbines to the site and land rents. In the UK it is often not possible to install the largest turbines available on the market due to planning restrictions. Vestas’ V112 is a 3MW machine with 112 metre blade span with a typical tip height of 140 metres. There are rare examples of planning consents that allow for 145 metre tip heights which would allow such a turbine to be used. In general the UK market is limited to the V90–3.0MW machines with a tip height of 125 metres. The smaller blade length and lower hub height reduce the output from a site, this increases the cost compared to a larger, taller turbine. Arup estimated the cost of offshore wind projects contracting today to be between £131-£167/MWh. Vestas considers that costs would typically be towards the lower end of that range. Arup assumed the lower range of operating costs to be £117,000/MW/pa. We consider that operating costs are likely to be below this level for Energy and Climate Change Committee: Evidence Ev 67

most projects. The cost of offshore is again determined by the wind speed of the site. It is also determined by the distance from shore. In general offshore wind has higher balance of plant costs (non-turbine costs) than onshore wind. Costs such as construction, foundation and cabling costs are greater offshore. It also has substantially higher operation costs. There are a number of significantly larger machines under development, including the V164 which Vestas is developing. The V164 is a 7MW turbine with a blade span of 164 metres. Larger turbines mean fewer are needed for a given capacity wind farm. Fewer turbines require fewer foundations and less cabling between the turbines, which also help to reduce costs. The V164 will have an output voltage of 66kV, whereas most turbines have a 33kV output. This enables more turbines to be connected on each string. This can reduce the length of the inter-array cabling by around a third. When looking to reduce costs it is important, particularly offshore, to look at operational costs as well as capital costs. The cost of operating and maintaining an offshore wind turbine is a much higher proportion of levelised cost, compared to onshore. When developing the 7MW turbine Vestas has focussed as much on minimising operational cost as capital costs. Based on the large scale deployment of turbines such as the V164, Vestas considers that it would be possible for the cost of offshore wind to fall to below £100/MWh for projects contracting in 2020. This is consistent with the findings of the Offshore Cost Reduction Taskforce.

How much support does wind power receive compared with other forms of renewable energy? The level of support under the Renewables Obligation is currently under review. The proposed level of support for onshore wind of 0.9 Renewable Obligation Certificates (ROC)/MWh would see onshore remain in the middle of the range of support levels. Offshore wind currently receives 2ROC/MWh but projects commissioning after March 2015 will receive 1.9ROCs and those commissioning after March 2016 will receive 1.8ROC/MWh. Hydro is proposed to be supported by 0.5ROC/MWh and the support for the various types of biomass generation is due to be altered. Support for landfill gas is being reduced to zero. Support for co-firing is due to remain at 0.5ROC/MWh for most stations and increase from 0.5 to 1ROC/MWh for enhanced conversion. It is proposed marine technologies will receive 5ROC/MWh up to project caps. All renewable power receives a Exemption certificate (LEC) which is potentially worth £5.09/MWh.

Is it possible to estimate how much consumers pay towards supporting wind power in the UK? (ie separating out from other renewables) In 2010–11 7,678,727 ROC were issued for onshore generation and 5,016,832 ROCs were issued for offshore wind generation. Each ROC cost the consumer £51.34. This means the total cost to the consumer of RO support is around £394 million for onshore and £258 million for offshore wind. Domestic consumers do not pay the Climate Change Levy so do not bear the cost of the LEC support.

What lessons can be learned from other countries? Ireland is a very good example of how increased use of wind power can reduce consumers’ bills. Wind meets around 17% of Ireland’s annual electricity demand. It has a mandatory pool market. Every MWh of power must be traded through the market. The half hourly price is derived from the bids that every single generator submits into the market every half hour. Put simply, a half hourly “merit order” is created, whereby every MWh is stacked up from cheapest to most expensive. The half hourly price is the bid from the most expensive MWh needed to meet demand. In some hours, when wind output is high, wind can set the wholesale price. This called the “merit order effect”. A Redpoint study in 2011 found that the merit order effect was greater than the cost of the REFIT, the feed in tariff for wind in Ireland. Wind is therefore already saving consumers in Ireland over €5 per year and that the savings could increase to €38 by 2020.

What methods could be used to make onshore wind more acceptable to communities that host them? The majority of people in host communities already find wind farms acceptable. There are, however, often highly vocal groups of local residents that opposed wind farm proposals. Early engagement can help communities become more accepting of projects. Similarly if communities are able to have genuine input to the project it can greatly increase acceptance. First-hand experience from those already living near operating wind farms can greatly help allay the fear of the unknown that can often drive people’s concern. Greater demonstration of direct and relevant benefit to the host community could also help public acceptance. In other countries such as Denmark and Germany members of the local community are often investors in wind projects. Having a direct financial link to a wind farm can make local people more accepting of new developments. July 2012

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