The future of Britain's electricity networks - Energy and Climate Change Contents

4 Making distribution smarter

133.  Massive investment in Britain's distribution networks took place in the 1950s and 1960s, and now, as with the transmission system, many of these assets are coming to the end of their natural life. The need for renewal provides an opportunity to 'future proof' the networks, allowing flexibility to incorporate new technologies.[241] In this Chapter we look at the changing role of the distribution networks; the importance of investment and innovation for developing a smart grid; and the current means by which distribution network operators (DNOs) recoup their costs.

The changing role of distribution

134.  Britain's 14 distribution networks deliver electricity from the transmission system to consumers via successive stages of transformation from higher to lower voltage systems. Power flows in one direction and is fairly predictable in terms of daily and seasonal demand fluctuations. This traditional approach could face a major shake-up with the development of more active management of the networks by the DNOs. As a chief executive of one of the companies told us: "[…] the role of the distribution network will be very different in five, 10, 15 or 20 years' time".[242] In this section we consider the various developments in electricity generation and consumption that will facilitate the creation of a smart grid that involves active demand-side participation, and some of the technical and regulatory challenges which must be overcome.


135.  Since the introduction of the Renewables Obligation (RO) in 2002 there has been a steady increase in the number of renewables projects, mainly wind farms, connecting at the distribution level, either because they are too small or not close enough to connect to the transmission system. This is known as distributed or embedded generation. The Government's target for 15% renewable energy by 2020 may lead to an increase in the amount of new distributed generation coming on-stream in the next decade. In addition, from 2010 feed-in tariffs will provide financial support for new small-scale low-carbon electricity generation up to 5 MW. The Department hopes this will encourage households, communities and organisations, such as schools, hospitals, universities and businesses to consider installing renewable technologies, such as wind turbines, combined heat and power systems or solar photovoltaics.[243] This smaller type of generating capacity is usually referred to as microgeneration.

136.  The distribution networks are able to manage easily the level of generating capacity currently connecting to their systems. The Minister told us up to 3.5 GW of microgeneration could be absorbed without the need for network reinforcement.[244] There is also substantial headroom for larger forms of distributed generation, depending on its size and location.[245] Moreover, financing and planning consent are currently the main barriers to new distributed generation.[246] It is not yet clear what impact the new feed-in tariffs will have. The Institution of Engineering and Technology told us, however, that as the level of capacity grows beyond a certain point, the cost of connecting it would increase significantly. Investment in the distribution networks is, therefore, important to create more flexibility before the system reaches this 'knee point'.[247]


137.  In addition to changes in the supply of electricity at a local and household level, the next decade will see developments in how consumers use energy. One area will be the take-up of electric vehicles. Though still at an embryonic stage, the electrification of the transport sector could be a key part of a future decarbonised energy system. Space heating too could largely be provided by electricity. The resulting changes to the demand profile of households and businesses will present new challenges to the design and operation of the distribution networks. The heating and transport sectors will also have the potential to provide a significant energy storage capacity that has, hitherto, not existed. We examined in Chapter 2 the role this could play in coping with the intermittency of wind generation, thus allowing a greater level of distributed generation to connect to the networks than would otherwise be the case.[248]

138.  Further changes on the demand side should arise from the national roll-out of smart meters to all households over the next decade. They will provide real-time information to consumers about their energy usage, which will be relayed automatically to electricity suppliers. The Government believes smart metering will make households more aware of how they use energy, hopefully resulting in behavioural changes that reduce their consumption. Smart meters could also allow companies to offer more sophisticated pricing tariffs that enable customers to manage their demand so they consume more during periods when the system is less constrained. Looking further ahead, it is envisaged that energy companies could control remotely household appliances, determining the operation of washing machines, dish washers and immersion heaters overnight, for example, according to the availability of supply. The charging of electric vehicles could also be managed in the same way. Hence, smart meters are seen as a vital enabling technology for the creation of a smart grid.[249]


139.  Smart metering and financial incentives for household and community renewables provide the means for people to become more engaged with their energy consumption, and their potential role in reducing carbon emissions.[250] Although, as one witness noted, consumers "[…] will always be more interested in soap operas than in exactly how the power system is being balanced".[251] Therefore, if DNOs are to manage greater levels of distributed generation, and make best use of the flexibility provided by the remote operation of appliances and vehicle charging, they will have to play a more active role in managing electricity demand and supply across their networks.[252] At the same time, a large expansion in the level of distributed generation could in the future give rise to situations where the distribution system exports electricity back into the high voltage transmission network. This will require an additional role for the DNO in managing power flows at the interface of the distribution and transmission networks. Whereas at present there is only one system operator, National Grid, which balances demand and supply across the entire system, it is possible to envisage a situation where the DNO may become a system operator as well.[253] The Minister told us that at present this issue was "an open question".[254]

140.  Creating a smart grid poses regulatory challenges. For example, the introduction of EU electro-technical standards for household appliances will provide the necessary functionality for the development of 'smart demand'.[255] Elsewhere, DNOs will need the appropriate incentives to encourage them to take a more active role in managing their networks. Dr Jim Watson told us: "the rules and regulations we have are designed for the incumbent system and they have served us well, but they will probably have to change fairly radically […]".[256] Phil Baker and Dr Bridget Woodman of the University of Exeter noted: "there are few incentives for DNOs to invest in technologies, which would allow their networks to be more actively managed".[257] Prof Goran Strbac noted, for example, that electricity sold on the wholesale market can more than double in cost by the time it reaches consumers, reflecting the cost of transmission and distribution services to transport the electricity from the generator to the customer. In contrast, distributed generation that is located near to the source of demand may circumvent these costs and, therefore, have a higher value than conventional generation. However, these potential benefits are not fully recognised within the regulatory framework. Prof Strbac told us: "Realising the value of distributed generation and responsive demand […] requires the creation of a level playing field".[258] This means fair treatment in terms of network access and charging for both generation and demand, and within the BETTA market.

141.  There are also technical challenges involved in the delivery of a smart grid. The distribution networks were not designed to accommodate large volumes of small and medium-scale generation. Potential difficulties include: accommodating bi-directional power flows; maintaining electricity flows at a level that is consistent with equipment ratings; ensuring voltage variations remain within safe and statutory limits; and ensuring power flows from local generation do not create short-circuit currents in the event of network faults.[259] Several witnesses told us many of these issues are already well-understood by engineers, though there is a lack of experience to date in applying the solutions in a smart grid context.[260] We discuss the available incentives to adopt new technologies later in this Chapter.

142.  For DNOs to take on a system operator role will also require the installation of sophisticated information, communication and control technologies to monitor and control the electricity system.[261] These will be needed to manage, for example, the potential unpredictability of greater levels of embedded generation. The ability for all parts of the system to communicate with one another will be a vital component of smart grids. This will require a highly capable communications platform, able to meet a demanding set of requirements, including coverage, reliability, responsiveness and security.

143.  There are various technologies available in Britain that the communications regulator, Ofcom, is considering as options for providing smart grid services, including the 3G mobile network and fixed line broadband. However, countries such as the US that have already begun to deploy smart grid technologies have eschewed these solutions because they either do not provide reliable coverage or operate at sufficiently low cost. Instead, they have opted for a 'wireless mesh' approach. This is a communications network made up of radio nodes, which allows appliances and smart meters to speak to one other. The technology works best on sub-1 GHz spectrum because the radio waves can travel further and penetrate deeper. However, there is a lack of suitable spectrum currently available in the UK, which is preventing companies wishing to deploy the 'wireless mesh' approach from entering the market here. Ofcom is currently consulting on the future use of the 872-876 MHz and 917-921 MHz frequency bands, which could be ideally suited for smart grid use.[262] One of the companies keen to develop 'wireless mesh' technology told the regulator that allocating this spectrum for the smart grid would "enable the rapid deployment of cost-effective, standards-based communications technology that will place the UK among the worldwide leaders in smart grid deployment".[263]

144.  In the future there could be potentially thousands of generators connected to the distribution networks at scales varying from domestic solar panels to large wind farms. Energy demand could also evolve and increase through the electrification of the transport and heating sectors. The deployment of smart grid technologies, such as smart meters, will therefore be crucial to the effective and economically efficient management of an increasingly complex energy system. This necessitates a fundamental rethink of the role of distribution companies who in the future will need to play a more active role in balancing demand and supply across their networks, potentially taking on a local system operator role.

145.  Creating smarter distribution poses significant challenges. Although many of the technical aspects are well-understood there is relatively little experience of their application to the smart grid. Furthermore, the regulatory framework does not at present provide a level playing field for the adoption of smart grid solutions, such as active demand management. Ofgem must address these issues in the coming years. One area in which we believe it could make an immediate difference is to work with Ofcom to ensure the allocation of suitable spectrum for smart grid use as soon as possible, thus enabling the full range of smart grid technologies to be considered for deployment in Britain.


146.  The DNOs are regional monopolies. This means that, in the same way as for the transmission system, the ownership and operation of the distribution networks is permitted under licence from Ofgem, the terms of which restrict the revenue of each DNO. The regulator reviews these revenues every five years through a Distribution Price Control Review (DPCR) that, when agreed, establishes a programme of network investment the DNOs will carry out over the next five years. Ofgem operates an RPI-X approach, which links DNOs' revenues to the rate of inflation, therefore encouraging them to make operational efficiencies. One of the companies, Electricity North West Ltd, told us since privatisation RPI-X regulation had led to firms halving their work forces and their costs, while doubling the quality of supply for consumers.[264] These achievements are significant because electricity distribution accounts for around 17% of households' bills as opposed to 4% for transmission.[265]

147.  The chief executive of one of the DNOs, CE Electric UK, told us "After 20 years of radical reductions the price cannot keep coming down and […] investments […] need to come forward now".[266] In 2009 Ofgem conducted its fifth DPCR, which will run from April 2010 to April 2015. One of its objectives is to allow companies to renew assets that have become age-expired, replacing them with higher specification equipment that will increase the capacity of the networks. Scottish and Southern Energy told us the review needed to provide "a stable platform for investment, adaptation and growth".[267] E.ON UK said: "The framework must also recognise the need to provide for network developments for both known connection projects, and also the expected large number of unknown connection and development requirements".[268] Electricity North West Ltd expressed a similar view, highlighting reinforcements in Cumbria and Manchester it could proceed with which would accelerate the connection of low-carbon generation in those areas.[269]

148.  In December 2009 Ofgem published the outcome of DPCR5. It has allowed the DNOs to collect revenues of around £22 billion over the five-year review period. Charges will rise by an average of 5.6% each year, although this will vary according to company, ranging from a fall of 4.3% per annum to a rise of 11.1%. The regulator estimates this will add an extra £4.30 each year to households' bills. The DPCR also establishes clear outputs for each of the DNOs which they must deliver in return for the revenues they will receive from customers. This means they will not be able to outperform their settlement by allowing their networks to deteriorate. A key aspect of the review is the consideration given to the future role of distributed generation and demand-side management, acknowledging the fact that the previous regime had encouraged investment in transformers and cables over other potentially more cost-effective options. One way DPCR5 seeks to address this is through the equalisation of incentives so the regulatory framework will treat network investment, network operating costs and closely associated indirect costs in the same way.[270] We consider other outcomes of the DPCR in the remaining sections of this Chapter.

149.  We welcome the outcome of Ofgem's fifth distribution price control review (DPCR), which seems to balance the requirement for network renewal on the one hand, with the need to minimise the resulting impact on consumers' bills on the other. However, the success or otherwise of the DPCR will need to be assessed against whether it encourages a significantly greater role for distributed generation and demand-side management within the energy system over the review period, and the extent to which it leads to the deployment of smart grid technologies.

The role of innovation

150.  The creation of a smart grid will require significant investment in research, development and deployment (RD&D) by the transmission and distribution companies. It is an area where British industry is potentially well-positioned to be a world leader. The probable large expansion of renewable power over the next decade, combined with relatively little interconnection with other countries, means Britain will need to deploy smart grid technologies sooner than many other countries.[271] The rewards could be huge. The Department of Energy and Climate Change estimates the size of the global industry could be £27 billion over the next five years.[272] However, many of our witnesses told us current levels of RD&D expenditure by the industry were insufficient and that this was a direct consequence of the early RPI-X framework, which encouraged the minimisation of operating costs over the DPCR period by 'sweating assets', and did not reward investment in innovation that would reduce firms' costs in the longer term.[273]

151.  In the last DPCR Ofgem acknowledged the impact the regulatory framework had had in running down RD&D levels by introducing two new incentive mechanisms for network companies—Registered Power Zones (RPZs) and the Innovation Funding Incentive (IFI). RPZs are a way of encouraging distribution companies to develop innovative ways of connecting distributed generation. One example is a scheme on the Orkney Islands that has used active network management technology to allow multiple renewable generators to connect to the system without the need for expensive network reinforcement.[274] The Institution of Engineering and Technology described the RPZs as "world-class developments".[275] However, still only a handful have been established in the five years since the scheme's introduction.

152.  The IFI has fared similarly. It aims to encourage DNOs to invest in R&D that focuses on the technical aspects of network design, operation and maintenance. The Incentive allows companies to pass on to customers 80% of their R&D costs up to a maximum of 0.5% of their total revenues. The industry has generally welcomed the initiative.[276] Scottish Power described it as a "resounding success".[277] Another said it was "excellent".[278] However, network companies have failed to make full use of the allowance. In 2007/08 National Grid spent £3 million on R&D, while the DNOs spent a total of £12.1 million, representing just 0.33% of their revenue, and well below the £5.4 million and £20 million respectively available to them. The Minister told us: "the kindest interpretation is that it reflected a rather static situation".[279] Although this represents a sizeable increase since 2005, when R&D activity for the DNOs totalled less than £1 million per annum, many feel the industry is still not investing enough given the scale of future investment required.[280] As the Institution of Engineering and Technology put it: "There is [still] little culture of innovation in much of the industry".[281]

153.  Whilst the very low base from which R&D has needed to grow is the primary reason for the slow take-up of the IFI, witnesses also told us the incentives themselves were not strong enough.[282] Furthermore, one DNO described the rules governing the areas they could innovate in as "narrow and strict".[283] In response, some have called for the level of the IFI to be significantly increased up to 2% of network companies' revenues and for its scope to be widened.[284] However, in the latest DPCR Ofgem decided to keep it at 0.5%. The regulator noted in its submission that the underspend by network companies demonstrated the current provision was sufficient.[285] It argued also, though, that one of the main challenges was in encouraging companies to apply the lessons learnt in the laboratory in commercial demonstrations.[286] Several DNOs agreed with this view with one telling us: "We do not need to invent things that do not exist, but we do need to apply them and really understand how they would work".[287]

154.  Accordingly, in the new distribution price control period Ofgem introduced a £100 million per annum Low Carbon Networks (LCN) Fund, the aim of which is to encourage DNOs to trial the new technologies, systems, and commercial and network operating arrangements that are necessary for the deployment of the smart grid. The fund will provide 90% of the financing for projects with DNOs expected to make up the rest. Ofgem will allocate each of the firms a proportion of the funds, though it will distribute the majority (around £320 million) through competition. The regulator also wants the network companies to share learning and this will be a condition of their receiving funds. Firms that do not apply the lessons learnt from projects conducted under DPCR5 will not receive funding for their own trials in future price control periods.[288] Ofgem hopes the IFI in combination with the LCN Fund will increase the level of RD&D within the networks sector to more than the 2.5% of revenue that is the Government's economy-wide target.[289]

155.  Looking to the future, the role of innovation in delivering the networks needed to support a low-carbon energy system forms a key part of Ofgem's RPI-X@20 review. The regulator's current emerging thinking is to introduce a single innovation stimulus for all the energy networks sectors that builds on the new LCN Fund. The regulator would also like it to be open to non-network parties, such as communications companies. Funding would be available for all types of innovation, ranging from R&D to commercial demonstration trials.[290]

156.  Elsewhere, the Government has also made available greater public funding for R&D, including £30 million to support the infrastructure required for low emission vehicles, and £6 million for a Smart Grid Demonstration Fund. Further funding is also available through the Technology Strategy Board and the Energy Technologies Institute—a public/private partnership that aims to invest up to £110 million a year over the next decade on the development of low-carbon energy technologies, including the smart grid.[291]

157.  The level of research and development conducted by the networks sector has risen significantly over the last five years, though still represents just 0.33% of firms' income. If Britain is to be one of the first to deploy smart grid technologies on a wide scale, the industry must invest sufficiently to turn what is at present a vision into a reality. To the extent that the lack of R&D is a result of the rules governing companies' expenditure under the Innovation Funding Incentive, Ofgem should look again at this matter. To the extent that the underspend is the result of the absence of a "culture of innovation", the industry must accept that it has failed in its responsibilities and that it needs to show significant improvement not just in the interests of both the nation and the consumer, but also to grasp the huge opportunities that the global market offers.

158.  We welcome the introduction of the Low Carbon Networks Fund and the continuation of the Innovation Funding Incentive. We recommend Ofgem keeps both these mechanisms under review with the aim of increasing the available funding for both within the current distribution price control period if there is demand. We welcome also new public sector funding for smart grid demonstrations, and hope the Government will continue to support this area despite the current fiscal constraints.

Embedded benefits

159.  In Chapter 3 we examined how National Grid levies Transmission Network Use of System (TNUoS) charges on generators and demand to cover the costs of maintaining and operating the grid. These charges consist of locational tariffs and additional flat tariffs, known as the residual. The current framework for transmission charging treats distributed generation as negative demand. In other words, it is seen as offsetting local demand. Because of this, distributed generators do not pay the TNUoS generation tariff and also usually receive a payment from the TNUoS demand tariff. In simple terms, because such generators are nearer to the point of end-use for electricity, they have historically avoided the charges associated with transmitting power over the transmission system. This is known as an embedded benefit.

160.  Since the establishment of the British Electricity Trading and Transmission Arrangements (BETTA) in 2005 Ofgem and National Grid have been concerned about the treatment of distributed generation within the charging regime. Both believe there is a case for generators paying the non-locational part of the TNUoS generation charges, and no longer receiving a payment through the non-locational part of the TNUoS demand tariff. In other words, they argue that if generators were charged on a cost-reflective basis they should only receive a reward from the part of the TNUoS charges that relate to location. The residual element is the largest part of the TNUoS charges. National Grid estimates that if distributed generators only received the embedded benefit from the locational element of the charges, then it would fall from around £20 per kW to between £6.25 and £7.25 per kW.[292]

161.  The regulator has placed a licence condition on National Grid to implement an enduring set of arrangements by 2011. Accordingly, in January 2010 the company published a pre-consultation on modification GB ECM-23, which proposes two models. National Grid's preferred option would treat output from distributed generation and transmission-connected generation as having a broadly similar impact on the need for transmission infrastructure investment. Distributed generators would pay both the Transmission Network Use of System (TNUoS) and the Balancing Services Use of System (BSUoS) generation tariffs that are also levied on transmission-connected generation, minus a discount that reflected the avoided local investment.

162.  The second option would still treat embedded generation as negative demand, but it would pay for the net electricity flow that physically passes onto or off the transmission system. This approach is supported strongly by the renewables industry, though National Grid believes this option would not treat transmission and distribution-connected generation in the same way in terms of the costs they incur across the whole network.[293] The firm also believes it would be more expensive and time-consuming to implement. In evidence to the Committee the Minister agreed that reform of the treatment of distributed generation would be necessary, stating: "[…] on a network with a lot more DG capacity, there may be a case for looking at whether the charging principles as they stand at the moment are right".[294]

163.  Generators connected to the distribution networks do not currently pay transmission network use of system charges because it is assumed their output is absorbed by local demand and therefore reduces the need for transmission capacity—a concept known as 'embedded benefits'. The level of distributed generation, particularly renewables, could increase significantly in the next decade, to the extent that local supply will at times exceed local demand, resulting in spillovers back into the transmission system. Moreover, where renewable generation is intermittent, transmission capacity will still be necessary to respond to shortfalls in supply. For this reason, the current treatment of embedded generation is not sustainable in the long run.

164.  Because the proportion of distributed generation in the electricity mix is still very low, there is no need for Ofgem and the industry to reach an immediate decision on an enduring set of arrangements. Instead, it should wait until it can be shown clearly that distributed generation is impacting on the transmission system. We recommend the regulator develops a set of criteria to determine when it would be appropriate to reconsider this issue as the risk of change too soon is that it may exacerbate the 'lock-in' of a centralised energy system. Central to the debate over the two options proposed by National Grid is the question of whether in the future there should be separate regulatory frameworks for the distribution and transmission networks, or if there is a case for regulating the whole system as a single entity. The regulator must resolve this question first, which forms part of its RPI-X@20 review, before it can conclude on an enduring set of charging arrangements for distributed generation.

241   Ev 152, para 57 (Department of Energy and Climate Change) Back

242   Q 235 (Electricity North West Ltd) Back

243   Ev 151, para 46 (Department of Energy and Climate Change) Back

244   Q 385 (Minister for Energy) Back

245   Q 335 (Ofgem) Back

246   Q 242 (CE Electric UK) Back

247   Q 296 (Institution of Engineering and Technology) Back

248   Ev 103, para 7.1 (ABB) Back

249   Ev 152, para 58 (Department of Energy and Climate Change), Ev 206, para 25 (National Grid) and Ev 258, para 9.4 (Scottish Power) Back

250   Qq 248 (CE Electric UK) and 41 (Dr Michael Pollitt, Judge Business School, University of Cambridge) Back

251   Q 256 (CE Electric) Back

252   Ev 152, para 56 (Department of Energy and Climate Change) and Ev 258, para 6.9 (Scottish Power) Back

253   Q 339 (Ofgem) Back

254   Q 423 (Minister for Energy) Back

255   Ev 190, para 41 (Institution of Engineering and Technology) Back

256   Q 2 (Dr Jim Watson, Sussex Energy Group) Back

257   Ev 278 (P.E. Baker and Dr B. Woodman, University of Exeter) Back

258   Ev 264 (Prof Goran Strbac, Imperial College London) Back

259   Ev 164 and (Energy Networks Association) and Ev 278 (P.E. Baker and Dr B. Woodman, University of Exeter) Back

260   Qq 296 (Institution of Engineering and Technology) and (CE Electric UK) Back

261   Ev 176, para 3.23 (E.ON UK) Back

262   Ofcom, Consultation on the way forward for the future use of the band 872-876 MHz paired with 917-21 MHz, August 2009  Back

263   Consultation Response by Silver Spring Networks Back

264   Ev 161, para 6.1 (Electricity North West Ltd) Back

265   Ev 232 (Scottish and Southern Energy) Back

266   Q 241 (CE Electric UK) Back

267   Ibid. Back

268   Ev 175, para 3.11 (E.ON UK) Back

269   Ev 159, para 4.4 (Electricity North West Ltd) Back

270   Ofgem, Electricity Distribution Price Control Review Final Proposals, December 2009 Back

271   Ev 254 (Scottish Power) Back

272   Department of Energy and Climate Change, Smarter Grids: The Opportunity, December 2009 Back

273   Ev 116 (British Wind Energy Association), Ev 164 (Energy Networks Association), Ev 218 (Dr Michael Pollitt, Judge Business School, University of Cambridge), Ev 269, para 4.1 (Prof Goran Strbac, Imperial College London) and Ev 273, para 20 (Sussex Energy Group) Back

274   Department of Energy and Climate Change, Smarter Grids: The Opportunity, December 2009 Back

275   Q 282 (Institution of Engineering and Technology) Back

276   Ev 112, para 28 (ARUP), Ev 164 (Energy Networks Association), Ev 177, para 3.28 (E.ON UK) and 202 (National Grid)  Back

277   Ev 259, para 10.1 (Scottish Power) Back

278   Ev 112, para 28 (ARUP) Back

279   Q 419 (Minister for Energy) Back

280   Ev 171 (Energy Technologies Institute), Ev 218 (Dr Michael Pollitt, Judge Business School, University of Cambridge) and Ev 274, para 25 (Sussex Energy Group) Back

281   Ev 191, para 50 (Institution of Engineering and Technology) Back

282   Ev 270 (Sussex Energy Group) and Ev 104 (Areva) Back

283   Q 245 (CE Electric UK) Back

284   Ev 202 (National Grid) and Ev 218 (Dr Michael Pollitt, Judge Business School, University of Cambridge)  Back

285   Ev 216, para 10.2 (Ofgem) Back

286   Q 333 (Ofgem) Back

287   Q 231 (CE Electric UK); and also Ev 177, para 3.28 (E.ON UK) and Ev 259, para 10.4 (Scottish Power) Back

288   Ofgem, Electricity Distribution Price Control Review Final Proposals, December 2009 Back

289   Q 343 (Ofgem) Back

290   Ofgem, Regulating energy networks for the future: RPI-X@20 Emerging Thinking, January 2010 Back

291   Ev 152, para 63 (Department of Energy and Climate Change) Back

292   National Grid, Pre-Consultation: GB ECM-23 Transmission Arrangements for Distributed Generation, January 2010 Back

293   Ibid. and Qq 183 (Renewable Energy Association) and 185 (Scottish Renewables) Back

294   Q 414 (Minister for Energy) Back

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