The Resilience of the Electricity System - Science and Technology Committee Contents


48.  In this chapter, we consider the issues around short term resilience of the electricity system. The question of "will the lights go out?" is often raised in this context. This is, however, merely short-hand. In the event of a shortage, the lights going out would be the least of our problems. Society's dependence on electricity is becoming ever greater. Today, an electricity shortage has the potential to result in a catastrophic collapse in all modern communications and many vital systems. Recent decades have seen a dramatic increase in society's vulnerability to electricity shortages.

49.  In this chapter we give particular consideration to the resilience of the electricity system over this year and next when capacity margins are particularly tight. In addition we extend our analysis through to 2020 by which time the Capacity Market will have come into effect.

50.  The electricity system in Great Britain has historically been highly reliable and resilient. As the Institution of Engineering and Technology (IET) told us, the last time electricity resilience was an issue was the three day week in the 1970s.[55] National Grid told us that, at 99.99995%, the transmission system for England and Wales was the most reliable network in Europe.[56]

The Narrowing Capacity Margin

51.  As noted in Chapter 1 of this report, the capacity margin forecast for this winter (2014/15) and next (2015/16) was particularly tight. Here we examine how this situation could have arisen and what the implications are for resilience of the electricity system. Although there are many factors influencing the narrowing capacity margin, a central issue is the closure of old power stations, coupled to insufficient investment in new generation capacity.[57] Box 2 provides further information about how the capacity margin, and corresponding Loss of Load Expectation (LOLE), are calculated. A lower capacity margin or higher LOLE equates to a less resilient system.

Box 2: The Capacity Margin and Loss of Load Expectation (LOLE)
The capacity margin is the proportion by which the total expected available electricity generation exceeds the maximum expected level of demand at the time at which that demand occurs. It acts as an insurance against "occasional unexpected losses of power or surges in demand" and is normally expressed as the percentage calculated by:[58]

Total available capacity can be defined in two ways:

1.  In the past the gross capacity margin was calculated based on the total amount of electricity which could theoretically be generated at any one time.

2.  Now the de-rated capacity margin is more commonly used.[59] This is the average excess of available generation over peak demand. The de-rated capacity margin takes account of the fact that not all generation capacity will run at its theoretical maximum all of the time. This is particularly important for renewable generation, where the output at peak times can be considerably lower than the theoretical maximum.[60] This metric de-rates each generation type by a factor reflecting the "statistically expected level of reliable availability from that plant type."[61] Ofgem typically uses winter de-rating factors of:

·  Coal/biomass: 88%

·  Gas: 85-92%

·  Oil: 82%

·  Nuclear: 81%

·  Hydro/pumped storage: 84-96%

·  Wind: 17-24% [62]

It should be noted that gross capacity margins cannot be directly compared to de-rated capacity margins. As a broad reference, however, a 20% gross capacity margin, which was the typical aim in the past,[63] has been likened to a de-rated capacity margin of 4-5%, although this would depend on the precise plant mix and the de-rating factors chosen.[64] In this report we use the de-rated capacity margin unless stated otherwise.

Although National Grid and Ofgem still report on the capacity margin, Ofgem argues that the capacity margin is: "not a good indicator of risk, as it is an average value and provides no information about the variability around this average value."[65] Therefore, another measure, Loss of Load Expectation (LOLE) is also used. As described by Ofgem:

"The LOLE is the average expected number of hours per year in which supply is expected to be lower than demand under normal operation of the system. This means the number of hours per year when we expect National Grid to have to use mitigation actions, including the use of the new balancing services. The LOLE is still not a measure of the expected number of hours in which customers may be disconnected as National Grid is expected to use other mitigation actions ahead of controlled customer disconnections."[66]

52.  As part of Electricity Market Reform, the Government set a Reliability Standard of 3 hours LOLE per year. This means that the LOLE over the course of the year should not exceed 3 hours. As EDF Energy explain, however: "This does not mean 3 hours of blackouts per year; it means that, on average, there may be 3 hours per year when supply would not match demand and exceptional measures would be required to avoid significant effects on customers."[67]

53.  The capacity margin is affected by events, such as the technical failure of power stations. In June 2014, Ofgem forecast a de-rated capacity margin of 6.7% and a LOLE of 0.5 hours for winter 2014/15.[68] The capacity margin was expected to fall further to a low of 3% in 2015/16 before recovering in subsequent years.

54.  A series of unexpected power station outages and closures followed. In October 2014 National Grid revised the forecast for winter 2014/15 to a capacity margin of 4.1% and a LOLE of 1.6 hours.[69] A LOLE of 1.6 hours still comfortably meets the 3 hours LOLE Reliability Standard. National Grid were of the view, however, that there was still considerable uncertainty regarding potential further power station closures and the maintenance schedule of key generators.[70] A decision was therefore taken[71] to use New Balancing Services (NBS) to manage the risk by procuring additional capacity. It proved necessary to put NBS in place as the Capacity Market will not begin to operate until 2018. As National Grid explain, NBS comprised:

    "… two additional system balancing tools (Demand Side Balancing Reserve and Supplemental Balancing Reserve). These balancing tools will only be used as a last resort in the unlikely event of a shortfall of generating capacity in the electricity market and allow us to procure additional capacity over the winters of 2014/15 and 2015/16."[72]

55.  The first of these tools, Demand Side Balancing Reserve (DSBR), provides contracts to large electricity consumers who are willing to reduce electricity consumption, or provide generation from backup generators, during times of peak demand (between 4 and 8 pm on weekday evenings in the winter). Consumers entering into such contracts receive an upfront payment and further payments in the event that National Grid makes use of the service.[73]

56.  The Supplemental Balancing Reserve (SBR) provides contracts to generators when they commit to making a power station, which would otherwise have been closed or mothballed, available in winter.[74]

57.  For winter 2014/15, National Grid procured additional capacity using New Balancing Services. As Mike Calviou from National Grid explained, this has helped to boost the capacity margin from 4.1% to 6.1%:

    "For this coming winter, the market has delivered a 4.1% de-rated margin. We have taken action with our supplemental balancing reserve purchases to increase that to a 6.1% margin, and we think that is a level that we can manage the system with this winter."[75]

58.  Box 3 provides information about the capacity margins for 2014/15 with and without NBS. For winter 2014/15 National Grid contracted a total of 319 MW of DSBR across 431 individual sites with businesses, such as Tata Steel and Flexitricity,[76] at a cost of £2.25 million.[77] A total of 2025 MW SBR was contracted with two gas power stations and one oil fired power station[78] at a cost of £29.5 million.[79]. Together these New Balancing Services provide an additional, de-rated capacity of 1.1 GW.[80] The forecast cost of New Balancing Services for winter 2014/15 was £31.75 million at a unit cost of £19.3/kW.[81] Further costs would have been incurred if this capacity had actually been used. As the Rt Hon Ed Davey MP, DECC Secretary of State, told us, so far National Grid has not needed to make use of this additional capacity:

    "National Grid has purchased 1.1 gigawatts of balancing reserve to support the system. It has not had to use that at all, because we have got nowhere near a problem, but it is there; it sits outside the market and National Grid can use it if we have a problem at peaks. We do not anticipate that, but it is there as a sort of insurance policy."[82]

59.  For winter 2015/16, National Grid intends to put contracts in place for an additional 1.8 GW of de-rated capacity.[83] After this the Capacity Market will come into effect.

Box 3: Key Data
·  The total amount of electricity, which was generated in the UK in 2013, was 359 TWh. The total demand was 374 TWh. Interconnectors made a net contribution of 14.4 TWh.[84] The amount consumed, after transmission losses and consumption within the energy industry are taken into account, was 317 TWh.[85]

·  Peak electricity demand in Great Britain in 2013/14 was 54 GW.[86]

·  For 2014/15 the forecast mid-winter generation capacity was 71.2 GW. When availability and historic performance was taken into account, this was de-rated (see Box 2) to 58.2 GW.[87]

·  The forecast Average Cold Spell peak de-rated demand margin was 4.1% with a Loss of Load Expectation (LOLE) of 1.6 hours.

·  Once the New Balancing Services were included, the de-rated margin was 6.1% with a LOLE of 0.6 hours.


Power (measured in kilowatts, kW) is the rate at which energy (measured, for example, in joules or kilowatt hours, kWh) is generated or used:

power = energy ÷ time

1,000,000,000 kilowatts (kW) = 1,000,000 megawatts (MW) =1,000 gigawatts (GW) = 1 terawatt (TW)

60.  As a result of the actions taken by National Grid to improve the capacity margin, domestic consumers are highly unlikely to see power shortages. During our inquiry we heard that although the capacity margin had become tight, the right steps have now been taken to ensure supply meets demand. As Ofgem told us: "We are confident that National Grid has the right levers to keep the lights on."[88] Professors Newbery and Grubb noted: "there is no 'cliff edge' at which the lights go out, but rather an increasing array of options for managing tight conditions."[89] There is no reason to expect that these tools will not be effective in keeping the lights on. Indeed, witnesses praised National Grid's professionalism in balancing the system.[90]

61.  The Secretary of State, the Rt Hon Ed Davey MP, assured us that the lights would stay on:

    "We are expecting there to be about 1.8 gigawatts of supplemental balancing reserves for 2015-16. On the basis that that goes ahead, I am sure that the lights will stay on not only this winter but next winter as well."[91]

62.  This is not the impression one might get from coverage in the media, where the question of 'will the lights go out?' is often posed. In answer to this question, we conclude that because of the measures put in place by National Grid, the lights are unlikely to go out due to insufficient generation capacity.

63.  The real question is not about whether the lights will go out, but whether the measures taken to make sure they stay on are adequate, whilst not being over cautious, and effectively addressing all three sides of the trilemma. Professor Helm CBE suggested that putting in place last minute measures, such as New Balancing Services, to balance the system, would be costly. He argued that better forward planning should have been in place:

    "There will be a cost and a price: if you do things in a hurry short term, you are bound to have additional costs. But this does not detract from the point that you want never to be in this situation again. You want to get to a situation where you have a comfortable margin. Any reasonable, large-scale economy like the British economy, with its reliance on electricity, is vastly better off in a world in which it is quite content and has a bit of fat in its capacity margin so it does not have to worry about these kind of problems, which play down on the aggregate price in the market. To run around saying, 'Thank God we only have 4% [capacity margin], at least we are not spending money on mothballed power stations' is not a state of affairs that we want to get into."[92]

64.  The Rt Hon Ed Davey MP argued that the measures were not last minute:

    "First of all, it has not been last minute … These plans have been developed since the coalition came to power. I do regret that there has been a poor legacy, but we have been working on it. If you look through the history of our consultation and our announcements, they have not been just in the last week, month or year, but over a period of years. So I do not call that the last minute. Of course they come at a cost—absolutely. My job has been to make sure that we minimise that cost."[93]

The Government estimates that procuring New Balancing Services added: "less than £1 on the average household bill"[94] in the year 2014/15. This represents an increase of less than 0.2% on an average electricity bill of £586.[95]

65.  As Professor Helm noted, the situation regarding the capacity margin could have easily been much worse. Demand for electricity has declined substantially since the economic crisis began. If demand had continued to grow, capacity margins could have been much tighter: "We got lucky in one respect. We have crashed the economy—not deliberately, but the consequence of that is to buy us 10 years of time."[96]

66.  Irrespective of how this situation has arisen, it has been known for some time that ageing power stations would close and appropriate, long term action to ensure that capacity margins remain healthy has been late in arriving. As Professor Helm commented:

    "It is a quite extraordinary state of affairs for a major industrialised economy to find itself even debating whether there is a possibility that the margins may not be sufficient in electricity to guarantee supply, particularly in a context in which electricity is increasingly important to the economy, and where information technology and so on depend absolutely crucially on a continuous supply."[97]

67.  It is our view that it is not sound policy to sail so close to the wind. It seems that successive governments should have anticipated the shrinking capacity margin earlier and taken steps to address it. We note that without the economic downturn the situation could have been more critical. Our aim is not, however, to attribute blame for past failures, but rather to ask whether there is now sufficient rigour and planning to avoid such situations in the future.

The Capacity Market

68.  To provide enough capacity in future, the Government has now introduced a Capacity Market (CM) which will operate from 2018. It proved necessary to put New Balancing Services in place as an interim measure ahead of the Capacity Market coming into effect. An explanation about how the Capacity Market operates is provided in Chapter 1 of this report.

69.  During the course of the inquiry, we heard that many were supportive of the Capacity Market.[98] Others, however, were less enthusiastic:

    "We remain pretty sceptical of the need for a capacity mechanism. As I said before, historically the market signal has been able to provide the signal for new generation. There is an open question about whether you have a heavily interventionist government policy making decisions all over the place that you need yet more intervention, but the question is whether you try to roll back that intervention or intervene anymore. It seems very odd that we are providing a subsidy to coal-fired power stations on the one hand and at the same time spending a lot of money trying to reduce carbon emissions on the other hand. Reducing carbon emissions is a very sensible aim but doing it by keeping coal power stations running seems extremely odd. The effect of a capacity mechanism will be to add cost but that is back to that political choice about what price you want to pay for extra capacity, and the Government have decided that they think customers are willing to pay."[99]

70.  Great Britain is not the only country to introduce a capacity mechanism. Capacity mechanisms are increasingly being considered in Europe, although different countries are taking different approaches.[100] In the UK Capacity Market the Government defines the amount of capacity needed and a competitive auction is held to determine the price. An alternative approach is the capacity payment, where the price is pre-determined by a central authority. A few European countries have established mechanisms, including Ireland, Spain and Greece.[101] A Capacity Market is being set up in France for delivery of capacity in 2016-17.[102] Professor Mitchell from the University of Exeter considered that the Danish System Operator Energienet had a better system in place than Great Britain's Capacity Market for ensuring sufficient capacity:

    "If they feel that they need some more capacity of some other capability requirement, Energinet the [Danish] system operator, is able to say, "We need 300 megawatts of this", and then that can be competitively put out to tender if you need it. Then, if you do not need it, you do not have to tender for it, whereas our capacity mechanism is just based on giving out this money, even though things change all the time and it may be completely unnecessary, and it is the customers who pay in the end."[103]

71.  The first capacity auction in Great Britain, which procured capacity for 2018, concluded on 18 December 2014. This auction procured 49 GW of additional capacity at £19.40/kW with a total cost of nearly £1 billion.[104] As shown in Figure 4, fossil fuel power stations accounted for in the region of 68%[105] of the capacity procured. Procuring such a large percentage of capacity from fossil fuel generation is incompatible with the Government's wider policy aims to decarbonise electricity supply.

Figure 4: Capacity Procured in the Auction by Technology Type

Source: National Grid, Final Auction Results (January 2015): [accessed February 2015]

Capacity procured for 2018 in the 2014 capacity auction. Gas includes Combined Cycle Gas Turbine (CCGT) (45.2%) and Open Cycle Gas Turbine (OCGT) and reciprocating engines (4.3%). CHP = Combined Heat and Power. DSR = Demand Side Response.

Resilient networks

72.  Generation capacity is not the only factor affecting resilience. Investment in the resilience of the network itself is also important. Ofgem ensures that transmission and distribution network operators are making sufficient investment in the networks using its RIIO price controls as described in Chapter 1. As Ofgem explain:

    "RIIO stands for "revenue", which is the revenue that the companies get from running the networks, which is determined by a set of "incentives, innovation and outputs". We are trying to ensure that there was a real emphasis not just on how much revenue the companies are allowed but on what they have to deliver on that revenue … As I said before, they also have to pay out to customers under the guaranteed standards. That puts incentives on to the companies to make their networks as resilient as possible and to respond when issues arise."[106]

73.  Ofgem has recently completed a review of the RIIO price controls for electricity distribution networks. Dr John Roberts, FREng, appeared confident that this would allow sufficient investment in distribution networks.

    "I think we are spending a sufficient amount on the distribution network. We have just completed the price review for the distribution network with Ofgem, and that will come into effect on 1 April [2015]. I think that makes sufficient allowance for investment in the network to maintain the resilience of the network."[107]

Costs and benefits

74.  There is, of course, a trade-off between the costs of investing in resilient networks and in generation capacity and the benefits of doing so. The electricity system could always be made more resilient through additional investment, but it can never be infallible:

    "… there are all sorts of things that can go wrong. They can be mitigated, but it is impossible to avoid any form of risk. At the end of the day you have to balance issues like affordability and resilience. There are a whole set of issues there to be balanced."[108]

75.  The decision of how to balance resilience and affordability must ultimately be taken by the Government. As Guy Newey from OVO told us:

    "Ultimately the decision of how reliable you want the system to be is a political decision. Make no mistake, energy companies want to keep supplying energy to customers for quite obvious financial reasons but also because it is the right thing to do. The Government have ultimately got to decide whether they want to have a system that is resilient to a one in eight year, a one in 100 or a one in 200. The more resilient you make the system the more expensive you make the system and the more gold-plating you have. You will never be able to completely remove risk of course, but that ultimately is a political decision about balancing costs overall to a system and the ability of bill payers and taxpayers to match those."[109]

76.  The decision about how much to invest in resilience depends on how much consumers are able or willing to pay:

    "Steps have been taken by the distribution companies to increase resilience to severe weather events, including flood mitigation, use of insulated overhead line conductors, rebuilding lines to a heavier construction specification, increasing lightning surge withstand capability, and automated switching to isolate faults and restore supplies. Resilience could be further improved by even greater levels of investment (with resulting increases in consumer prices which Ofgem's consumer surveys have indicated would not be supported) but, whilst such events are highly inconvenient for those consumers affected, they do not threaten the integrity of the electricity system as a whole."[110]

77.  As noted above, Professor Helm argued that putting in place measures, such as New Balancing Services, to ensure a sufficient capacity margin will be costly. There are also concerns about the costs of the Capacity Market as a longer term measure to guarantee capacity. Fundamentally, there are arguments about what capacity margin is appropriate and so how much additional capacity should be procured. Professor Helm argued that running a system with low capacity margins increases costs:

    "If you run a system at a 4% or 2% margin the price will be higher. Everyone will pay a higher electricity price because the price needed to bring the market into equilibrium is higher, because the stuff is scarce."[111]

78.  Professor Newbery from the University of Cambridge, however, argued that while a healthier capacity margin might bring prices down, there may be consequences of this which need to be considered:

    "… if you over-procure capacity then the nominal cost is about £2.5 billion but the net cost to consumers is less than that because the prices will be lower. A larger capacity margin means lower prices in the wholesale market. But that has consequential effects. Two of them are that the cost of supporting renewables goes up because the difference between the wholesale price and the strike price [under Contracts for Difference] increases. If that goes up then the Levy Control Framework[112] restricts the amount of renewables you can put on the system, so there are adverse consequences for one of the main targets of the electricity market reform. If we lower the price in this country relative to other countries the economics of building interconnectors is undermined somewhat and, since renewable generation is imperfectly correlated the wider the area over which you trade, that disadvantages the penetration of renewable generation. It is true that the prices may come down but it would be unwise to ignore the adverse consequences of that."[113]

79.  Professor Helm suggested that a capacity margin of more than 10% was needed.[114] National Grid, however, were sceptical about whether such a high margin was necessary:

    "… over 10% on a de-rated basis would be a very, very comfortable margin, which I would be surprised if the market was consistently delivering because at that level there would be some generators that would probably never run."[115]

80.  There does, however, seem to be uncertainty as to whether the current margins are enough, particularly if the electricity system experiences a high-impact, low-probability event. Dr Roberts described a rare event of this type as a 'Black Swan' event:

    "As far as the supply is concerned, I would have the concern that the supply margin is quite small now … I think what we are worried about are the Black Swan-type events that suddenly happen and whether we have sufficient generation. I would argue perhaps that we do not, but—and this is, I think, the core of the report that we have just produced—we do not really have a good sense of what the costs would be if we did have those sorts of outages: hence, we do not have a benchmark against which to judge how much we should spend, because system security comes at a price."[116]

81.  To provide a comparison, EDF Energy supplied us with information about the capacity margin in France.[117] EDF Energy noted that it was not straight forward to compare the capacity margins between the two countries, as peak demand in France is very sensitive to cold weather. In France, LOLE is therefore the preferred measure. As shown in Table 1, France has a higher forecast LOLE for each year through to 2018/19. As Professor Newbery told us: "We [GB] have the same loss of load expectation standard [three hours] as France and Germany. Belgium has two and a half times as high."[118] Meanwhile, the Republic of Ireland aims for a LOLE of 8 hours per year and the Netherlands aims for 4 hours per year.[119]

Table 1: France and UK comparison (LOLE)
France 2014/15 2015/16 2016/17 2017/18 2018/19
Expected energy unserved3.3 GWh 15 GWh23 GWh 14 GWh9 GWh
Loss of load expectation1h 4h5h45 4h2h30
Surplus or deficit of capacity2,900 MW -900 MW-2,000 MW -800 MW500 MW
Great Britain2014/15 2015/16 2016/17 2017/18 2018/19
Expected energy unserved0.5 GWh 4.2 GWh0.8 GWh 0.3 GWh1.9 GWh
Loss of load expectation36mins 3h4854mins 18mins1h48
Surplus or deficit of capacity1,659 MW -224 MW1,225 MW 2,103 MW465 MW

Source: Supplementary written evidence from EDF Energy (REI0053).

It should be noted that for Great Britain, the LOLE provided for 2014/15 is the LOLE following the procurement of additional capacity by National Grid using New Balancing Services (NBS). The LOLE presented for 2015/16 does not take NBS into account.

82.  The question therefore remains of what the capacity margin for Great Britain should be and whether the Government is seeking to procure the right amount of capacity through the Capacity Market. Professor Newbery considered that the Government is being overcautious:

    "We think that understandably perhaps politicians, and particularly Ministers, are so nervous about the concept of the lights going out—and in particular the Daily Mail-type views that that might happen—that they are overcautious, and that has high costs …"[120]

83.  Professors Newbery and Grubb have undertaken an analysis, which suggests that the Government may be over procuring capacity, in part because it has not taken the potential contribution of interconnection with other countries into account:

    "We argue costs can be substantially reduced by deferring some of the associated auctions. At the heart of this is the (somewhat unfashionable) conclusion that the UK electricity is more resilient to the risk of "capacity shortfall" than widely assumed. Our analysis concludes that 53.3GW is likely to be excessive, particularly but not exclusively in its (lack of) assumed contribution from interconnectors. Political fear of 'the lights going out' can easily become a catch-all argument for excessive procurement, and associated subsidy to incumbent generators."[121]

84.  We also heard that there is a lack of information about the amount of backup generation which is available. Such backup generation could potentially participate in the Capacity Market:

    "In addition, there is large capacity of industrial backup generation, mostly diesel—the only estimate we found was an estimate of 20GW, a huge volume which if correct, and made available at times of peak need, would negate any significant risk of capacity shortfall; the apparent lack of any official estimate of this capacity appears to be an important lacunae which should be corrected as a priority."[122]

85.  Professor Grubb noted that there appeared to be no firm published statistics on the amount of industrial backup available, but suspected it could play a considerable role in providing capacity. [123]

86.  Dr Roberts considered that it would be useful to establish a national inventory of emergency power:

    "It would be a good thing [to establish a national inventory of available emergency power]. Nobody has done it. It is starting to happen. There are commercial organisations out there now that are in contact with large organisations. For example, some of the big supermarkets all have back-up generation in their stores.

    Aggregating all of that, they can sell that to the electricity generators as an amount of back-up generation that could be available, and that can be sold to the generators as an economic proposition: "You pay us the money and we can bring this back-up generation into play". It is beginning to happen on a commercial basis. But some kind of index or database right across the UK of the back-up generation to my mind does not exist, and it would be a very useful thing if it did."[124]

87.  The Government decided how much capacity to procure through the Capacity Market based on the newly introduced Reliability Standard of 3 hours LOLE. As the Government explained, the Reliability Standard was introduced: "primarily to inform how much capacity to buy in the capacity market."[125] The Reliability Standard is intended to trade off: "the cost of additional capacity against the potential costs of disruption."[126] It aims to provide security of supply at a level the consumer is able and willing to pay for.

88.  This raises the question of how the Reliability Standard of 3 hours LOLE was arrived at. The Reliability Standard was defined based on the Value of Lost Load (VoLL). As EDF Energy explained:

    "VoLL is the price that customers would be willing to pay to avoid losing electricity supply. In practice, of course, this price varies between different customers and between different times; nevertheless, it provides a useful guide to determine how much money should be spent to deliver security of supply."[127]

89.  There are different ways of measuring the potential costs of electricity shortfalls and there is some debate about which method is most appropriate. Professors Grubb and Newbery questioned whether the VoLL, used to calculate the Reliability Standard, is appropriate:

    "The 'Loss of load probability' is also set on the basis of security standard which in terms of the estimated Value of Lost Load (VoLL) is likely to be excessive from a purely economic standpoint, as we explain in our paper, because it reflects estimates of domestic VoLL but is then applied in practice to industrial VoLL."[128]

90.  In 2013, London Economics published a report on the VoLL.[129] This used a 'stated preference' approach, where consumers were asked how much they were hypothetically willing to pay to avoid an electricity outage or conversely how much they were willing to accept to undergo an outage. The VoLL arrived at in this report was used by the Government to set the Reliability Standard of 3 hours LOLE.[130] This VoLL is based on the value for domestic consumers and small and medium enterprises (SMEs). It does not include large commercial and industrial consumers because: "they are assumed either to be able to participate in the capacity market through demand side response, or else to be able to change their electricity use in response to price signals."[131]

91.  In November 2014, the Royal Academy of Engineering published a report which considered the costs of electricity outages and how to measure VoLL.[132] The report describes three different methods of calculating the cost of an outage to consumers: stated preference, revealed performance and economic modelling. Commenting on the approach taken by London Economics, the report stated: "The choice experiments were conducted in a highly rigorous fashion; however, they represent just one possible method among a number of options, and are subject to the uncertainties inherent in stated preference methods."[133]

92.  The Royal Academy of Engineering acknowledged that it is less than ideal to base cost-benefit decisions on such uncertain estimates, but noted that considerable further research would be needed to develop a more robust assessment method.[134] Dr Roberts, a co-author of the report, told us that further research was needed into the costs of shortfalls in electricity supply:

    "I think we need to do a lot more research. Very little research has been done in this country, as our report points out. There has been one Ofgem inspired piece of research, which was done by London Economics in 2013. That is the only piece that we could find in this country. The rest of it has been done elsewhere in western Europe. We do need to do more research: a combination of trying to establish what the cost would be for individual consumers, small businesses and large businesses, but also looking at what has happened in the real world—at the significant events that have happened elsewhere, both in Europe and in other parts of the world, and after the event to get a hard database of evidence."[135]

93.  Dr Roberts emphasised the need for future large scale investment across the whole electricity system in both generation and in networks, and the need to communicate the case for such investment more effectively with the public:

    "For me, the most important point is to make the public at large aware of the fact that we need to make substantial investment in our electricity infrastructure. Apart from the decarbonisation point, which I put to one side, simply put we have an infrastructure that is ageing. Many of our power stations were built in the 1960s with an economic theoretical life of 30 years, which is now well exceeded. Ditto a lot of our distribution networks were built in the 1960s, again with an economic life of 20 to 30 years. So we need to invest a lot of money in our network as a whole to make it more resilient, and we need to communicate that message to the public at large: they may not like it but electricity is going to get more expensive if you want to enjoy the level of resilience that you have enjoyed to date."[136]

94.  Additionally, on the point of communicating with the public, Dr Roberts stated:

    "At the moment the public at large are very sensitive to electricity prices, almost to the point, I think, where they say, 'I am paying this much a year for my electricity. I expect you to make sure that it is there all the time. That is what I am paying for, am I not?' Saying, 'No, you have to pay some more now to make sure it is there', might not go down very well, even though it may be entirely justified in technical and economic terms."[137]

95.  There has been much discussion, and media coverage, around high energy prices in the UK. Indeed, Ofgem has referred the retail energy market to the Competition and Markets Authority for investigation. As shown in Figure 5, however, compared with other EU countries, the price paid by consumers in the UK for electricity is not particularly high. Although the pre-tax electricity prices in the UK are amongst the highest, the overall cost is kept down as taxes in the UK are low relative to those in other countries.

96.  Making comparisons between different countries is, however, always difficult owing to differences in reporting criteria. The UK figure for taxes includes only VAT, which is currently set at 5%, the lowest rate allowed under EU regulations.[138] In Germany, for example, VAT on electricity is set much higher at 19%. This does not, however, account in full for the higher taxes paid by domestic consumers in Germany. In addition to VAT, Germany's tax figure includes other charges such as 'electricity tax' and 'renewables levies,' whereas in the UK the costs of energy and climate change polices are included as an integral part of pre-tax electricity prices.[139] According to analysis by DECC, these costs accounted for 15% of the average domestic electricity price (including tax) in 2014.[140] Based on their central fossil fuel price scenario, DECC estimates that this will increase to 27% in 2020 and 29% in 2030 (see Table 2, para. 217).

97.  UK consumer prices are not out of line with other countries in Europe, although they are much higher than in the United States. If a resilient system is to be maintained, ongoing investment in the whole system will be needed. As Professor Roberts suggested, it may be that a more honest discussion with the public is needed about what this is going to cost. Fundamentally, when making decisions about how much to invest in resilience, it would seem prudent to have robust data on the costs of electricity shortages. In future, as the electricity system changes, there will be novel risks to resilience and the balance of costs and benefits is likely to change. The cost of resilience, in light of these future challenges, is discussed further in the following chapter of this report.

Figure 5: Average Annual Electricity Prices

Average Domestic Electricity Prices without and with taxes. The UK compared to the International Energy Agency (IEA) countries. Pence per kWh. Data for 2013. Data is not available for Australia, Canada and Spain. Excluding tax data is not available for Korea. The 'excluding tax' price for the USA was estimated using a weighted average of general sales taxes and fuel taxes levied by individual states.

Average Industrial Electricity Prices without and with taxes. The UK compared to the International Energy Agency (IEA) countries. Pence per kWh. Data for 2013. Data is not available for Australia, Canada, Korea, New Zealand and Spain. The 'excluding tax' price for the USA was estimated using a weighted average of general sales taxes and fuel taxes levied by individual states.

Source: DECC, International Energy Price Comparison Statistics (accessed December 2014).

98.  We conclude that successive governments should have anticipated the shrinking capacity margin earlier and taken steps to address it. As a result of inaction, the narrow capacity margin which emerged posed a threat to resilience. This has been mitigated using expensive measures with a heavy reliance on fossil fuel generation. This is not a good example of how the trilemma can be most effectively balanced. We recommend that the Government takes a more rigorous approach to long-term planning to avoid such situations arising in the future. Furthermore, we recommend that the Government reassesses whether it is procuring the right amount of capacity through the Capacity Market to offer an optimal cost-benefit balance to consumers.

99.  In order to make effective decisions on resilience, reliable information about the true costs of electricity shortfalls is needed. We are surprised to find a paucity of information in this area. We recommend that the Government funds further research into the costs of shortfalls and publishes its findings. This information should be used to determine whether the current Reliability Standard is appropriate for making decisions on the procurement of capacity.

100.  We recommend that the Government reviews the contribution interconnection and industrial backup generation could make to capacity margins. It is not currently clear how much industrial backup generation is potentially available. We recommend that the Government identifies and publishes information on the amount of industrial backup generation which could be made available.

55   Written evidence from the Institution of Engineering and Technology (IET) (REI0032) Back

56   Written evidence from National Grid (REI0017) Back

57   RAEng, GB Electricity Capacity Margin (October 2013): [accessed February 2015] Back

58   Ibid. Back

59   RAEng, GB Electricity Capacity Margin (October 2013): [accessed February 2015]; Written evidence from The Institution of Engineering and Technology (IET) (REI0032) Back

60   Due to e.g. unfavourable weather conditions. Back

61   RAEng, GB Electricity Capacity Margin (October 2013): [accessed February 2015] Back

62   Ofgem, Electricity Capacity Assessment Report 2013 (June 2013): [accessed February 2015] Back

63   Of the Central Electricity Generating Board (CEGB), former nationalised owner and operator of the England and Wales electricity network and generation (1957-1990). Back

64   RAEng, GB Electricity Capacity Margin (October 2013): [accessed February 2015] Back

65   Ofgem, Electricity Capacity Assessment Report 2014 (June 2014): [accessed February 2015] Back

66   Written evidence from Ofgem (REI044) Back

67   Written evidence from EDF Energy (REI0030) Back

68   Ofgem, Electricity Capacity Assessment Report 2014 (June 2014): [accessed February 2015]; National Grid, Winter Outlook 2014/15 (October 2014): [accessed February 2015] Back

69   National Grid, Winter Outlook 2014/15 (October 2014): DownloadAsset.aspx?id=36714 [accessed February 2015] Back

70   Ibid. Back

71   Following consultation between National Grid, Ofgem and DECC. Back

72   Written evidence from National Grid (REI0017) Back

73   Written evidence from National Grid (REI0017) Back

74   Ibid. Back

75    Q54 Back

76   National Grid, 'Companies win contracts for reducing power demand': [accessed February 2015] Back

77   This includes £1.1 million set up fees, £150,000 administration fees and an estimated £1 million of testing costs.  Back

78   National Grid, SBR Winter 2014/15-Contracts Confirmed (November 2014): [accessed February 2015];  Back

79   This includes capability fees of £23.5 million and estimated warming/testing costs of £6 million. Back

80   The 1.1 GW of additional capacity takes the de-rated capacity margin from 4.1% to 6.1%. Back

81   Supplementary written evidence from National Grid (REI0060) Back

82    Q188 (the Rt Hon Ed Davey MP) Back

83    Q188 (the Rt Hon Ed Davey MP); National Grid, SBR and DSBR Market Update (December 2014): [accessed February 2015] Back

84   DECC, Digest of United Kingdom Energy Statistics 2014 (July 2014): system/uploads/attachment_data/file/338750/DUKES_2014_printed.pdf [accessed February 2015 Back

85   The difference between demand and consumption is accounted for by the 29 TWh used within the energy industry and 27 TWh of losses. Back

86   Ofgem, Electricity Capacity Assessment Report 2014 (June 2014): [accessed February 2015] Back

87   National Grid, Winter Outlook 2014/15 (October 2014): DownloadAsset.aspx?id=36714 [accessed February 2015] Back

88   Written evidence from Ofgem (REI0044) Back

89   Written evidence from Professor David Newbery and Professor Michael Grubb (REI0026) Back

90    Q50 (Professor Dieter Helm);  Q165 (Dr John Roberts) Back

91    Q188 (the Rt Hon Ed Davey MP) Back

92    Q50 Back

93    Q188 (the Rt Hon Ed Davey MP) Back

94    Q188 (Jonathan Mills) Back

95   DECC, Estimated impacts of energy and climate change policies on energy prices and bills. (November 2014): [accessed February 2015] Back

96    Q50 Back

97    Q44 Back

98   Written evidence from EDF Energy(REI0030); Written evidence from Energy UK (REI0034); Written evidence from the Nuclear Industry Association (NIA) (REI0020) Back

99    Q37 (Guy Newey) Back

100   Leonie Meulman and Nora Méray, Capacity Mechanisms in North West Europe (November 2012): [accessed February 2015] Back

101   ACER, Opinion of the Agency for the Cooperation of Energy Regulators no. 05/13 on Capacity Markets (2013): [accessed February 2015]; Ben Caldecott and Jeremy McDaniels, Stranded generation assets: Implications for European capacity mechanisms, energy markets and climate policy (2014): Stranded%20Generation%20Assets%20-%20Working%20Paper%20-%20Final%20Version.pdf [accessed February 2015] Back

102   Thomas Veyrenc, Réseau de transport d' électricité , 'A capacity market in France: status of discussions and future steps' (presentation), (24 April 2014): 3rd_european_energy_forum/T.Veyrenc.pdf [accessed February 2015] Back

103    Q144 Back

104   National Grid, Final Auction Results (January 2015): Shared%20Documents/Final%20Auction%20Results%20Report_v3.pdf [accessed February 2015] Back

105   This figure includes gas and coal/biomass (for which disaggregated figures were not reported). It does not include CHP and autogeneration, although much of this is gas-fired. Back

106    Q182 (Maxine Frerk) Back

107    Q154 Back

108    Q18 (Sarah Rhodes) Back

109    Q35 (Guy Newey) Back

110   Written evidence from the Institution of Engineering and Technology (IET) (REI0032) Back

111    Q50 Back

112   The Levy Control Framework was put in place to control the costs to consumers of its energy and climate change policies. Rather than funding these initiatives directly, the Government obliges energy companies to do so. The costs are then recovered through consumer bills. To control these costs the Treasury, through the Levy Control Framework, places a cap the amounts that can be raised and spent through this mechanism. Back

113    Q71 Back

114    Q50 (Professor Dieter Helm) Back

115    Q54 (Mike Calviou) Back

116    Q154 Back

117   Supplementary written evidence from EDF Energy (REI0053) Back

118    Q73 (Professor David Newbery) Back

119   DECC, Annex C: Reliability Standard Methodology (2013): uploads/attachment_data/file/223653/emr_consultation_annex_c.pdf [accessed February 2015] Back

120    Q70 (Professor David Newbery) Back

121   Written evidence from Professor David Newbery and Professor Michael Grubb (REI0026) Back

122   Ibid. Back

123    Q72 (Professor Michael Grubb) Back

124    Q158 Back

125    Q21 (Andy Shields) Back

126    Q25 (Andy Shields) Back

127   Written evidence from EDF Energy (REI0030) Back

128   Written evidence from Professor David Newbery and Professor Michael Grubb (REI0026) Back

129   London Economics, The Value of Lost Load (VoLL) for Electricity in Great Britain (July 2013): [accessed February 2015] Back

130   DECC, Annex C: Reliability Standard Methodology (2013): uploads/attachment_data/file/223653/emr_consultation_annex_c.pdf [accessed February 2015] Back

131   DECC, Annex C: Reliability Standard Methodology (2013): uploads/attachment_data/file/223653/emr_consultation_annex_c.pdf [accessed February 2015] Back

132   RAEng, Counting the cost: the economic and social costs of electricity shortfalls in the UK (November 2014): [accessed February 2015]  Back

133   London Economics, The Value of Lost Load (VoLL) for Electricity in Great Britain (July 2013): [accessed February 2015] Back

134   RAEng, Counting the cost: the economic and social costs of electricity shortfalls in the UK (November 2014): [accessed February 2015] Back

135    Q160 Back

136    Q156 Back

137    Q154 Back

138   DECC, Estimated impacts of energy and climate change policies on energy prices and bills. (November 2014): [accessed February 2015] Back

139   European Commission, Eurostat, Electricity Prices-Price Systems (2013): [accessed February 2015] Back

140   DECC, Supplementary Tables: Estimated impacts of energy and climate change policies on energy prices and bills. (November 2014): [accessed February 2015] Back

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