House of Commons - UK Energy Supply: Security or Independence?

UK Energy Supply: Security or Independence? - Energy and Climate Change Contents

5 Infrastructure resilience

Gas storage

67. Gas storage is a means of managing seasonal demand fluctuations—gas has tended to be put into storage in the summer months when gas is cheap and abundant and taken out in the winter months when demand and prices are higher.[119] The flexibility of gas storage facilities—in terms of the rate at which gas can be withdrawn and injected—is the crucial factor as to how well the facility can meet short term fluctuations in demand. DECC noted that gas storage would become increasingly important as the contribution of wind to electricity generation increased because gas fired power plants could provide cover for wind intermittency.[120]

STRATEGIC GAS STORAGE

68. In addition to gas stored in order to manage seasonal demand fluctuations, it has also been proposed that "strategic" gas storage could be built to hold gas stocks that could be released in a supply emergency, such as the strategic oil stocks held by members of the International Energy Agency (IEA). Professor Stern thought there was a case for such "strategic [gas] storage"—facilities commissioned, built and controlled by Government—but explained that "nobody else does".[121] Oil & Gas told us that the costs for strategic gas storage would be "absolutely astronomical".[122] A study on natural gas storage in the EU estimated that gas would cost five times as much to store as oil.[123] We will not consider "strategic" storage, and instead focus only on gas storage used to manage seasonal demand fluctuations.

DIFFERENT TYPES OF GAS STORAGE

69. There are three main types of underground gas storage: injection into water aquifers; into depleted oil and gas fields; and salt caverns.[124] Together these are described as underground gas storage (UGS). "Pore storage injection" (into depleted oil and gas fields, or aquifers) generally takes place during low demand between late spring and early autumn months, with withdrawals taking place throughout winter. Such facilities offer more seasonal storage that can balance demand requirements in the longer term. In contrast, salt caverns can be filled and emptied at a high rate, allowing them to deliver demand response in the medium to short term. Witnesses told us that in the future the UK was more likely to need the "quick-in, quick-out" storage facilities, rather than very large "quasi-strategic" storage.[125] [126]

NEED FOR INCREASED STORAGE

70. Gas storage could be used to moderate the effects of gas price spikes.[127] The gas market tends to overreact to supply threats resulting in a short period of very high prices.[128] The main problem is who is going to pay for such gas storage.[129]

71. The British Geological Survey (BGS) believed that the UK's energy security is "closely bound up with how much gas it stores", and that at present the country does not have the underground gas storage that would be expected when comparing the UK to other countries.[130] In the past the UK could meet changes in demand by increasing or decreasing output from the North Sea and East Irish Gas fields; however, these offshore fields are rapidly depleting and the market is losing its ability to respond flexibly.¹³⁴

72. The UK currently consumes about 100 bcm (billion cubic metres) of gas per year, but only has storage capacity equivalent to a little over 4% of this, which is much less than other European countries.[131] The UK's current storage capacity is equivalent to about 14 days' worth of supply, compared to 69 in Germany, 59 in Italy, 87 in France, and 66 days in the US.[132] The Sussex Energy Group argued that "an increase in the UK's gas storage capacity is long overdue" adding that it would increase the resilience of the UK's gas supply infrastructure.[133]

73. Many witnesses thought that the UK probably needed to double the amount of gas storage it currently had (about 4.4 bcm) by 2020.[134] BP told us that in order to bring gas storage capacity in line with other major EU Member States, the UK should increase its capacity to about 15 bcm.[135]

74. The Minister told us that, taking into account facilities that were under construction or had had planning consent, the UK's gas storage could increase four-fold by 2020.[136] However, Professor Stern believed that in the current commercial climate, many of these proposed projects were unlikely to be developed.[137]

IMPACT OF INTERMITTENT RENEWABLES ON GAS STORAGE

75. The issue of gas storage is likely to worsen as the proportion of intermittent renewable generation increases, since more flexible gas-fired power plants may be required to provide "backup" when the wind does not blow.[138]This requires "fast cycle" gas storage.[139]The UK's storage capacity may need to double by 2020 as more renewables come on stream.[140]

GAS IMPORTS

76. DECC emphasised to us that the "huge growth" in the UK's LNG import capacity increased resilience to supply interruptions.[141] However, other witnesses did not agree with suggestions that LNG was a wholly relevant replacement for physical gas storage.[142]

77. The UK needs more gas storage capacity capable of delivering gas at a high rate. The Department of Energy and Climate Change should be concerned about the lack of gas storage used to manage seasonal demand fluctuations. It should aim to double the UK's current gas storage from current levels by 2020 in order to avoid exposure to gas supply interruptions and price spikes, and, in the longer term, to ensure a resilient gas supply to flexible gas plants acting as "backup" to intermittent electricity generated from wind.

INCENTIVISATION AND ECONOMICS OF GAS STORAGE

78. Oil and Gas UK explained to us that investment in gas storage had been hindered by "various obstacles".[143] Other witnesses also argued that new gas storage facilities were not being delivered because the economics did not stack up. Oil & Gas UK told us that "When gas prices are low, no one wants storage; when gas prices are high, no one can afford storage".[144] Gas storage company Stag Energy added:

[…] it is unlikely that most of the time there will be a price signal for storage, because it is one of these paradoxes that it is only when it is too late and there are severe conditions that the price signal is there.[145]

79. Centrica Energy also explained why an oversupply of gas—due to a combination of increased LNG availability and reduced demand owing to the economic downturn—had reduced the difference between winter and summer prices; as this seasonal price differential reduced there was less incentive to build facilities where gas is bought cheaply in the summer and stored in order to sell in the winter.[146]

80. Centrica is currently evaluating plans for a further 2.4 bcm of storage capacity at its proposed Baird Gas Storage Project, at a depleted offshore gas field off the North Norfolk coast.[147] However, they described the economics as "marginal at present".[148] It was this seasonal price differential that was the "key driver of value of these kinds of storage facilities".¹⁴⁷ While there was widespread agreement that the economics of gas storage remained challenging, there was not agreement on how this problem should be solved. We were provided with a range of different options.

81. The Minister agreed that the real problem with gas storage was that "the economics do not add up", a problem that the Government aimed to solve through measures proposed in the current Energy Bill currently going through its parliamentary stages.[149]

SHARPENING PRICE SIGNALS

82. The Energy Bill contains measures designed to strengthen the market incentive for ensuring sufficient gas is available during a Gas Supply Emergency. A "supply emergency" (which has never happened to date)[150] is defined as "an emergency endangering persons and arising from a loss of pressure in a network or any part thereof" caused by an inability to match supply and demand.[151] Under the current arrangements, the gas price is frozen for the duration of the supply emergency, which Shell stated would "limit the effectiveness of price signals" to attract more gas into the UK if the price was frozen below market prices in continental Europe.[152] The Bill would give Ofgem powers to unfreeze the gas price in an emergency, which Shell said would "put a premium on stored and/or flexible gas" and act as an incentive for investment in gas storage.[153]

83. DECC believed that these measures would "sharpen the commercial incentives" for energy suppliers to meet their contractual obligations during a Gas Supply Emergency, and therefore the likelihood of such an emergency would be reduced.[154] However, Clause 79 of the Energy Bill, which deals with security of gas supplies, does not make explicit reference to gas storage. Stag Energy argued that DECC's proposals in Clause 79 went "against general industry advice" on what was needed to incentivise gas storage.[155] While these "sharpened" price signals may attract gas from continental Europe to the UK—unless a gas supply emergency was also being experienced on the continent—it is unlikely that this would incentivise the construction of new gas storage in the UK as industry would be unwilling to tie up large amounts of capital on the chance that it may receive a high price for stored gas in a supply emergency.

PUBLIC SERVICE OBLIGATION

84. National Grid and the Energy Networks Association concluded that their favoured option to support the development of gas storage was an amalgamation of the current "market based" approach with "suitable obligations".[156] Stag Energy believed a Public Service Obligation (PSO) would be "guaranteed to produce a [certain] level of storage".[157] A PSO could be placed on all gas suppliers, based on their sales in the previous year, and be designed so as to meet a targeted increase in gas storage capacity.[158] Professor Stern agreed that the best way to incentivise investment in the fast response gas storage that the UK needed would be a contractual obligation on suppliers.[159] However, the Gas Forum argued that imposing PSOs on companies to store gas would "undermine the market".[160] PSOs tended to be used in markets that are "illiquid", where there is no ability to buy flexibly, which was not the case in the UK.¹⁶⁰

GOVERNMENT INTERVENTION

85. Witnesses disagreed over whether Government intervention was necessary. While some saw it as a priority,[161] others regarded it as premature.[162] Shell believed that direct Government intervention in the market risked "crowding-out private sector investment" in storage.[163] Stag Energy, however, saw a role for Government to "set out a framework" to guide industry.[164]

86. The Minister did not want to be "prescriptive", Government preferred to "create a framework" and leave it to industry to decide.[165] He hoped gas storage would be a part of the solution, but believed the market should determine how supply obligations were met.[166] However, in its Electricity Market Reform White Paper 2011, the Government proposed to increase and ensure electricity security by "contracting for security of supply" through a "capacity mechanism", the details of which they were currently consulting on.[167] One of the options DECC asked to be considered was a "Strategic Reserve" mechanism in which a "central body" would procure reserve electricity capacity and withhold it from the market, to be released when prices rise above a certain level (for instance, due to a decrease in renewable electricity supply due to a lack of wind) in order to cap market prices.[168]

87. The Government needs to explain and justify why it believes a strategic reserve is needed to ensure a secure supply of electricity—as suggested in its Electricity Market Reform White Paper 2011—but does not consider it necessary to intervene in the gas market to ensure more gas storage is delivered.

88. The UK needs to significantly increase its gas storage capacity. The Government must develop a strategy for achieving this. Doing nothing—or continuing to give inconsistent signals to the market about which approach it will choose—could result in no storage being built. This would diminish energy security.

Oil stocks

89. The UK is required to hold emergency oil stocks as part of its membership of both the EU and the International Energy Agency (IEA). Under Council Directive 2006/67/EC on Strategic Oil Stocks, EU Member States are required to maintain minimum stocks of petroleum products equal to at least 90 days of the average internal consumption during the previous calendar year.[169] As a crude oil producer the UK has a derogation that reduces the obligation by 25% to 67.5 days consumption.[170] David Odling, Oil and Gas UK's Energy Policy Manager, thought this derogation would be lost later this decade as production from the UKCS declined.[171]

90. The above directive will be repealed at the beginning of 2013 by Council Directive 2009/119/EC, which will bring all Member States into line with the existing rules of the IEA. The new directive requires Member States to maintain a total level of oil stocks corresponding to at least 90 days of average daily net imports (rather than consumption). In February 2011 the IEA calculate that the UK has 476 days' worth of oil imports in stock.[172] DECC'S projections foresee oil imports rising from 2011 onwards, while demand remains flat.[173] Therefore, stock requirements based on imports will require the UK to increase its capacity. As all of the UK's stocks are currently held by industry, the increased costs would have to be borne by them under the current arrangements. When the UK loses its derogation as an oil producer it would require £4-5 billion of additional strategic oil storage infrastructure.[174] The UK Petroleum Industry Association (UKPIA) argued that an independent agency, funded by industry in order to coordinate oil stocks, would bring the benefit of "slightly lower costs", but, more importantly, it would be "managed in a transparent way, rather than by individual companies".[175]

AN INDEPENDENT STRATEGIC OIL STOCK HOLDING AGENCY

91. In the UK, all strategic oil stocks are held by industry, whereas other countries tend to have a mix of public and privately-held stocks.[176] The "big difference" between public and private stocks is that the cost of the latter have to be borne by industry, but Professor Stevens argued that in practical terms "there is not a great deal of difference".[177]

92. UKPIA told us that most other Member States have recognised the "national" aspects of strategic oil stocks, and manage them through an independent stockholding agency, rather than leaving it to private industry.[178] In the light of declining North Sea oil production, UKPIA urged the Government to establish such an independent agency, explaining that the independent agency could be:

[...] completely self-funding […] it will be a transfer really from the individual amounts that individual companies are [already] catering for […] there will still be some form of charge from the [independent] agency to the obligated companies.[179]

The Minister believed that that the UK policy of leaving it to the market has "delivered long-term security".[180] Even so, DECC are "reviewing [their] future approach to holding oil stocks", and while they excluded the idea of public owned stocks they acknowledged that there was scope for an "industry owned and operated central stockholding agency".[181] They intend to consult on this issue in 2012.

93. We recommend that the Government set up an independent central agency, funded by the industry, to manage strategic oil stocks.

Electricity Infrastructure

94. The Government's Electricity Market Reform (EMR) White Paper was published during the course of our inquiry. It contains proposals designed to "ensure the future security of electricity supplies; drive the decarbonisation of our electricity generation; and minimise costs to the consumer".[182] Legislation is expected in the next session, which starts in early summer 2012.

GENERATION INFRASTRUCTURE

95. There are two major challenges for electricity generation in the UK. The first is that by 2018, approximately 19 GW of existing capacity is due to close as aging plants come to the end of their lives or are forced to close under environmental regulation.[183] About half of this is nuclear capacity coming to the end of its working life and half oil and coal capacity closing under the Large Combustion Plant Directive. Some recent forecasts of demand project that the level of peak demand will remain broadly similar to current levels out to 2020 (because the uptake of new technologies such as heat pumps and electric vehicles is expected to be broadly offset by offset by improvements in energy efficiency and embedded generation).[184] This means that the 19 GW will need to be replaced with new power plants in order to retain today's level of capacity margin.

96. A great deal of evidence suggested that the 19 GW "gap" will most likely be filled by new gas plant. The Minister told us "we have a crunch coming and the technology that is best equipped for dealing with that, where the plant can be built quickly, where the fuel we know is currently broadly available, is gas".[185]In fact, there is already approximately 12 GW of Combined Cycle Gas Turbine (CCGT) plant either under construction or with consent granted, with a further 12 GW in the planning system.[186] In addition, there is approximately 4.5 GW of wind plant under construction or with consent granted.[187]

97. Ofgem pointed out that the timetables for some projects under construction or consideration will slip.[188] However, National Grid argued that despite this, there is probably sufficient new plant already coming through the system to fill the supply gap created by planned plant closures.[189] The evidence suggests they are correct.

98. Even though it is likely that some of the projects under construction or consideration will slip, we agree with National Grid that, provided it materialises, there is sufficient new plant already coming through the system to fill the 19 GW "gap" created by planned plant closures before 2020.

99. The second challenge is that the electricity sector needs to be almost entirely decarbonised by 2030 if the UK is to meet its long term climate change targets. According to the Committee on Climate Change (CCC) the average carbon intensity of the sector needs to be around 50 gCO₂/kWh by 2030 (compared with the current level of 490 g/kWh).[190]

100. This raises a question about the role for gas in the electricity system. A modern unabated gas plant has a carbon intensity of around 400 gCO₂/kWh.[191] While this is significantly lower than the carbon intensity of coal, it nonetheless represents a significant level of carbon emissions. The total emissions from a plant will depend on how often it is running. Base load power stations operate more or less continuously to meet the base level demand while others are brought in progressively as demand increases. Peak-load generation is used to satisfy short periods of maximum demand. "Mid-merit" or "load following" generation is that which falls between baseload and peak. Non-baseload generation that responds to demand is sometimes referred to as 'flexible' capacity. The Committee on Climate Change has said that beyond 2020:

"there is […] only a limited role for [investment in] unabated gas plant (e.g. running at low load factors in balancing intermittent generation). If there were to be investment in either form of unabated fossil fuel capacity [i.e. coal or gas] for baseload generation, required sector decarbonisation would not be achieved".[192]

101. According to calculations by International Power, unabated gas would be able to generate approximately 46 TWh energy in a year before reaching the 50g/kWh threshold (and of course, this is on the basis that there is no unabated coal or oil operating at all, which may not be a reasonable assumption). This compares to 165 TWh generated from gas in 2009.[193] It is therefore clear that the role for unabated gas in the electricity system in 2030 will be very much less than is currently the case.[194] This means that a balance needs to be struck between building enough new gas plants in the short-term to fill the "gap" between now and 2020 and ensuring that the number built is not so great that the UK misses its longer-term climate change goals or is forced to strand assets to avoid exceeding CO₂ budgets.[195] Emphasising short-term system stability over the long-term decarbonisation goals could lead to a "dash-for-gas", while focusing too heavily on climate change policy could stifle investment in new gas in the short term.

102. The Government's solution to this problem has been to propose an Emissions Performance Standard (EPS) that will initially only apply to coal but which would be reviewed and possibly tightened in 2015. Under the "grandfathering" principle, anything built before 2015 would be exempt from any subsequent tightening of the EPS for a suggested 20 year period.[196] This means that an unabated gas plant built in 2014 could in theory continue to operate as baseload capacity until 2034 and Government would have no power to either demand that CCS be fitted or to curtail operating hours. However, a very high carbon price in the future could serve the same function as an EPS by rendering high-carbon generation uneconomic.

103. We believe that the proposal for a weak Emission Performance Standard (EPS) coupled with 20 year grandfathering will result in a hectic "dash-for-gas" ahead of the 2015 review. This increases the risk of locking the UK into a high-carbon electricity system and represents a huge gamble on the eventual availability of cost effective Carbon Capture and Storage technology for gas plants. This could pose a severe threat to the achievement of our long-term climate change goals. Moreover, applying the EPS only to coal puts the government in the position of choosing technology winners, exactly the outcome that an EPS, by mandating an outcome not a particular technology solution, is supposed to avoid.

104. When we put this point to the Minister, we were alarmed by his suggestion that "if it were then considered that we were seeing too much gas coming on to the system, [as a result of the EPS arrangements] then that would be grounds for saying that we don't need to be seeing more consents to be granted".[197] Policy certainty is vital for attracting investment but changing the rules in that way would undermine confidence in the UK as a place to invest. The recent experience with feed-in tariffs for small-scale renewables is a case in point.

105. DECC needs to think through the implications of its Emission Performance Standard (EPS) proposals more carefully. Changing the rules after the fact to avoid a dash-for-gas will undermine investor confidence in the UK so it is essential to get the EPS right from the start. We have recommended on several occasions that a more effective approach would be to set out an EPS with a long-term trajectory in line with Committee on Climate Change recommendations. If Government is really resistant to specifying the level of an EPS beyond 2015, an alternative but less satisfactory approach would be to simply set a date by which Carbon Capture and Storage would be expected on all coal- and gas-fired power stations operating as baseload or at mid-merit level.

INTERMITTENCY AND SYSTEM FLEXIBILITY

106. Many of the respondents to this inquiry pointed out the potential threat that a significant increase in the use of intermittent renewables (mainly wind power) combined with a new generation of inflexible nuclear power stations could pose to managing supplies of electricity in the future.[198]

107. We heard that there are four measures that could help to tackle this problem:

More dynamic management of demand for electricity, in order to match demand with available supply. This could be facilitated by introduction of smart meters and smart grids.[199]
Greater interconnection with electricity grids in neighbouring countries to allow export of excess generation at periods of low demand and to import electricity at times of low generation and high demand.[200] (This is an area we explored in more depth in our recent inquiry on a European supergrid.[201])
Greater use of storage technologies to store energy at times of excess generation and to help meet demand at times of low generation.[202] This includes technologies that can store electricity (such as pumped hydro, compressed air and batteries[203]), thermal storage (where electricity is used to generate heat, which can then be stored, for example, as part of a district heating scheme[204]) and hydrogen (where excess generation is used to generate hydrogen, which can either then be converted back into electricity in a fuel cell or can be used directly as a fuel, for example by burning it in an internal combustion engine to power transport[205]). Batteries in electric vehicles could also provide a form of distributed electricity storage.[206]
The use of "back up" generation at times when supply does not meet demand. This requires the use of "flexible" or "despatchable" technologies where output can be rapidly ramped up and down. Examples include coal, gas, biomass, energy from waste, distributed combined heat and power plants, hydropower and tidal lagoons.[207] Using fossil fuels for this purpose may have implications for emissions of greenhouse gases.

108. There is still a great deal of uncertainty about the scale of this challenge and how it could be resolved. There does not seem to be any understanding about how much intermittency the current system could accommodate.[208] On top of this, no-one knows exactly what the future generation mix will consist of or how quickly and to what extent new technologies like smart meters and electricity storage will be able to mitigate intermittency problems. This makes it impossible to specify a precise solution at this point in time. However, we believe that it is likely that each of the four options set out above will have some role to play in the answer.

109. We recommend that DECC undertakes further work to enhance understanding of the role interconnection, storage and demand management can play both in enhancing energy security and in the context of its projections of generation demand in the future.

110. This challenge, while significant, is not an immediate threat. The Association of Electricity Producers noted that "increased penetration of intermittent renewables in the generation mix will not happen in one step rather it will evolve over time and potentially in parallel with other developments [...] this will allow time for developing a greater understanding and experience of system operation with a growing percentage of intermittent generation".[209] However, other European countries will also have to grapple with the problem of intermittency, possibly rendering interconnection less effective.

111. We believe that dealing with intermittency requires significant further research both in terms of scenario modelling and "learning from doing" activities such as smart meter trials. As we previously recommended in our report on Electricity Market Reform and a European Supergrid, the Government needs to investigate more thoroughly the potential impacts of intermittency on maintaining the energy supply and what the role of gas would be in balancing this intermittency in different scenarios.

CARBON CAPTURE AND STORAGE (CCS)

112. The Committee on Climate Change has suggested that any new baseload fossil fuel plant being added to the system after 2020 will need to be fitted with carbon capture and storage (CCS) equipment. However, most witnesses for this inquiry (including the Minister) were sceptical about the chances of CCS being commercially viable by 2020.[210] Indeed, there is increasing uncertainty about whether even the planned four CCS demonstration plants will be operational by 2020 since DECC and HMT are still "discussing arrangements" for how projects 2-4 will be funded.[211]

113. If CCS technology is not commercially available by 2020, the UK could face an energy dilemma: either provide energy security but exceed carbon budgets by running new unabated fossil plant; or, meet climate change obligations but risk energy security by shutting down (or using only very sparingly) unabated fossil plant.

114. The Government should draw up plans immediately for how the tension between climate and security goals will be dealt with if Carbon Capture and Storage is not delivered by 2020. This issue should be included in the energy security strategy.

115. We recommend that the Government asks the Committee on Climate Change to investigate—as a matter of urgency—the implications on long-term climate objectives of having large quantities of unabated gas plant on the system during the 2020s.

ELECTRICITY DISTRIBUTION NETWORKS

116. The UK's electricity distribution networks[212] currently provide a very high level of reliability; over 99% according to the industry association.[213] In order to preserve this level of reliability in the short- to medium-term, some investment will be needed to maintain the existing infrastructure.[214]

117. However, looking to the longer-term if we are to meet our climate change objectives, it is likely that there will need to be significant changes to both the physical distribution infrastructure and the way in which it is operated. According to the industry association, "this transformation will be different in shape and nature from anything that has gone before".[215]

Physical changes to networks

118. Respondents to this inquiry explained that electrification of heat and transport will result in significantly increased loads on distribution networks (the impact will be less on the transmission system because increased embedded generation will offset the impact of heat pumps and electric vehicles to some extent. This effect is not seen at the network level.).[216] There were concerns that unless networks were reinforced and demand actively managed, these changes in electricity usage would be likely to overload networks.[217] This would present a clear threat to energy security.

119. There appeared to be some discrepancy between the Government and industry view of when these upgrades will be required, and how much they are likely to cost. The Government's Electricity Market Reform White Paper states that "over £110bn needs to be spent on new generation, transmission and distribution assets in this decade".[218] However, the Minister confirmed that this figure did not include costs associated with local networks.[219] In supplementary evidence, the Minister told us that Ofgem had estimated that around £40bn of investment in transmission and distribution would be needed by 2020.[220] Ofgem provided estimates over a slightly longer timescale and suggested that by 2025, £21-27bn of investment in transmission and £26bn in distribution would be needed.[221]

120. The Distribution Network Operator (DNO) Electricity North West told us that the increased electricity load resulting from the use of electric heat pumps and electric vehicles could require a minimum of £250m investment in its network alone between 2015-2023 with a further £750m by 2030.[222] It also expressed some concerns about Ofgem's new regulatory framework ("RIIO") and whether this would allow sufficient investment in networks to keep pace with an ambitious programme of decarbonisation.[223]

OPERATIONAL CHANGES TO NETWORKS

121. The increased use of distributed generation,[224] and the need for demand side management (see paragraphs 141-145) to balance intermittent sources of power, will mean that Distribution Network Operators may need to take on a more active role in balancing networks in the future.[225] As noted by our predecessor Committee, DNOs may ultimately need to move away from the current relatively passive operation model towards becoming Distribution System Operators (with responsibility for balancing supply and demand on their network).[226] Such a significant change will require a great deal of planning and work from DNOs to ensure they are able to manage the transition effectively. We note that our predecessors recommended that such major changes could not be delivered by the market alone and would require strategic leadership from Government.[227]

122. Smart meters and smart grids are expected to play an important role in helping to facilitate demand side response and in balancing networks.[228] However, the Royal Academy of Engineering has suggested that current plans to introduce smart meters to every household by 2020 do not include the functionality required to manage electric vehicle charging, which could potentially render the first generation of smart meters obsolescent as the electric vehicle market grows.[229] In addition, Professor Kemp of the Institution of Engineering and Technology told us that the Government's approach to smart meters and smart grids was "back to front" and needed to start with a set of overall objectives (which might include managing the charging of electric vehicles so as not to overload the grid) to determine what functionality was needed in smart meters rather than starting with delivering smart meters and then deciding how they might be used.[230] We note that the Government's response to the consultation on smart meter implementation does suggest that smart meters should have the functionality to support the use of electric vehicles.[231]

123. Ofgem's Low Carbon Network Fund (LCNF) is funding a portfolio of projects that are designed to help the industry understand how to meet the changing needs of generators and consumers and how to ensure that the networks are prepared for the transition to a low-carbon economy. The first tranche of projects will explore how to make the best use of flexible demand from smart meters and smart white goods and ways in which electric cars can be charged without overloading the network (among other things).[232]

124. We recommend that the Department carries out a full review of the technical and cost implications to Distribution Network Operators of the electrification of heat and transport. It should also carry out a systems appraisal of the security benefits and risks of such electrification strategies, both at national and local levels.

125. We welcome the introduction of Ofgem's Low Carbon Network Fund, but recommend that Ofgem should also monitor what steps all Distribution Network Operators are taking to adapt their role to deal with increased distributed energy on the system and to facilitate demand side response. It should also liaise with the Department of Energy and Climate Change to ensure that the Low Carbon Network Fund trials that are now underway consider system security implications as well as those for emissions. The Department must ensure that DNOs are adequately prepared for dealing with distributed energy and demand side response.

Securing investment in infrastructure

126. It is clear that significant investment will be required in the UK's energy infrastructure in the coming decade. According to DECC, £110 billion of investment in electricity generation and transmission is likely to be required by 2020.[233] On top of this, investment is also likely to be needed in (among other things) local electricity networks,[234] gas transmission networks,[235] gas storage,[236] energy efficiency,[237] CCS,[238] load management[239] and offshore oil and gas operations.[240]

127. The table below shows Ofgem's estimates of the nature and level of investment required in the energy system under the four different scenarios investigated as part of its Project Discovery (which examined whether or not future security of supply could be delivered by the existing market arrangements). The scenarios are based on the combination of two drivers: the speed of global economic recovery and the extent of globally co-ordinated environmental action. This produced four scenarios:

Green transition (rapid economic recovery, rapid environmental action)
Green stimulus (slow economic recovery, rapid environmental action)
Dash for energy (rapid economic recovery, slow environmental action)
Slow Growth (slow economic recovery, slow environmental action)Table 1: Energy system investment figures estimated as part of Ofgem's Project Discovery

Source: Ev w36

Cumulative investment, £bn, 2025

Green transition Green Stimulus Dash for energy Slow growth

Nuclear 12.8 12.8 6.4 3.2

Renewables 67.2 62.7 35.7 31.3

CCS 15.8 16.7 3.3 0

CCGT 4.4 4.3 20.9 17.3

Distribution 26 26 26 26

Onshore transmission 19 19 17.3 17.3

Offshore transmission 7.9 7.4 4.3 3.7

Interconnectors 1 1 0.5 0.5

Energy efficiency 16 16 8 8

Renewable heat 52.8 52.8 9.5 9.5

Smart meters 10 10 10 10

LNG terminals 0.9 0.6 1.5 0.7

Gas storage 1.1 0.7 4.6 0.7

SCR 1.2 0.6 1.2 1.2

Total 236.1 230.6 149.1 129.4

128. We heard that there are many potential barriers to investment in UK energy projects. These included:

Changes to the offshore oil and gas taxation regime in the 2011 Budget were unexpected and may have undermined investor confidence by increasing perceived policy risk.[241]
Fiscal, policy and regulatory uncertainty around the development of CCS could inhibit investment in this sector.[242]
Policy uncertainty (particularly around electricity market reform) could lead to a hiatus in investment.[243]
A perceived focus on renewable and nuclear forms of electricity generation may undermine confidence in gas investment.[244]
The EU ETS carbon price is too low to stimulate investment in low-carbon generation.[245]
Falling global gas prices as a result of the recession, which have had a chilling effect on investment.[246]
The Weightman report on Fukushima will delay the interim design assessment of new nuclear power stations, which could delay investment in this area.[247]
Ofgem's regulatory regime (RIIO) may not allow sufficient rates of return for investment in networks to attract debt and equity investors.[248]
The nature of some infrastructure projects means that the returns are not of the right sort to appeal to investors (for example, district heating provides long-term, low returns rather than short-term high returns).[249]

129. The proposals in the Government's Electricity Market Reform White Paper are intended to "bring forward the level of investment needed in new low-carbon generation capacity and infrastructure at the required pace".[250] Our report on the Government's proposals contained an assessment of what investors needed in order to make new low-carbon electricity infrastructure an attractive investment proposition. We were disappointed that the White Paper did not address our concern that the proposed package of measures is too complex and may therefore introduce too great a level of political risk for investors.[251]

130. We also recognised that a delay in implementing the electricity market reforms could result in a hiatus in investment. We were pleased that DECC published its White Paper before the summer recess, but were very disappointed that it does not plan to legislate this session, as we recommended.[252]

131. Several respondents to this inquiry highlighted the importance of regulatory certainty and a stable policy regime for investor confidence.[253]

132. Government must give proper consideration of the long-term potential impact of changes to the tax regime on investment, especially where these are not the subject of advance consultation. The Government must also recognise that complexity is a barrier to investment and still has not been addressed.

119 DECC, Statutory Security of Supply Report, §4.3.27, November 2010 Back

120 DECC, Statutory Security of Supply Report, §4.3.27, November 2010 Back

121 Q 490 Back

122 Q 300 Back

123 Ramboll, Study on natural gas storage in the EU, DG TREN C1, Draft Final Report, October 2008, p192 Back

124 Ev w40 Back

125 Q 298 Back

126 Q 106 Back

127 Q 9, Ev w55 Back

128 Q 9 (Stern) Back

129 Q 44 Back

130 Ev w40 Back