Low carbon network infrastructure Contents

3Managing networks flexibly

52.Network impacts of low-carbon electricity generation are not confined to the initial process of connection. Wind and solar do not typically provide power at the steady, constant rate which coal, gas and nuclear plant can. Together, wind and solar met approximately 10% of the UK’s electricity demand in 2014, an approximately fourfold increase in absolute and relative terms since 2010.119 This proportion is set to more than double, to 24%, by 2020.120 Wind and solar are sometimes referred to as ‘intermittent’, but we heard from Dr Gordon Edge, Director of Policy at RenewableUK, that this adjective is inaccurate. He argued “wind and solar are variable: they vary with the availability of the resource, but they are also forecastable, whereas intermittency implies one or zero and a random move between the two” and noted that National Grid forecasts wind 24 hours ahead with 94% accuracy.121

53.We adopt Dr Edge’s preferred terminology, but the rapid expansion of variable renewables as a proportion of the UK’s electricity generation creates challenges for security of supply unless flexibly managed, meteorological advances notwithstanding. We considered three potential solutions in this inquiry. Technological advances in electricity storage could be a viable means to shift energy from times of peak supply to those of peak demand. Increased Demand Side Response (DSR), on the other hand, could mould electricity demand to the more-variable new shape of electricity supply. Interconnection between the UK and other European countries allows it to import electricity when needed and to export any surplus generated.


54.Variable generation could be managed by storing electricity at times of peak supply for use at times of peak demand. Electricity storage technology is advancing rapidly. We therefore examined the level of support that storage at different scales could offer networks now and in the future. There is a plethora of electricity storage technologies, encompassing a wide range of levels of capacity, response time, cost and maturity. Two broad categories of storage emerged as important: small-scale storage, typically in battery form, which could help DNOs and individual consumers balance their systems, and large-scale storage, such as Pumped Hydroelectric Storage (PHS) and Compressed Air Energy Storage (CAES), which could provide such services at the national level. Many witnesses complained about the regulatory framework for storage: we explored these concerns and the Government’s timetable to tackle them.

Large-scale storage

55.Pumped Hydro Storage (PHS) uses electricity to pump water up a reservoir, which can then be released back through turbines. PHS is the most mature storage technology, accounting for 99% of global storage installation.122 The UK has approximately 2.7 GW of PHS,123 of which approximately 1.7 GW is at a single site, Dinorwig.124 PHS can be built at large scale but only at certain sites due to geological requirements.125 Another form of large-scale storage is Compressed Air Energy Storage (CAES), which uses electricity to compress air and store it underground, where it can also be released back through turbines. Gaelectric is planning to develop a CAES site near Larne.126 We heard contrasting views on the future of large-scale storage in the UK: Dr Jill Cainey, Director of the Electricity Storage Network, a trade association, told us “there is potential for more pumped hydro storage in the UK” but that “it is very expensive up front” and “securing planning is one of the biggest issues”;127 Stephen Goldspink of Siemens argued “in the UK we won’t see anything like Dinorwig built again” due to “geographical restrictions” and that “more economic [storage] technologies are emerging”.128 National Grid told us that further PHS would be “a great service provider” to the System Operator.129 The Minister told us that the Government would “potentially” support large-scale storage.130

56.Further large-scale storage, such as Pumped Hydro and Compressed Air Energy Storage, could be of great value in managing variable generation, but there is uncertainty as to the potential for future deployment. We recommend that the Government commissions a study on the future of large-scale storage in the UK which includes consideration of potential sites and what support such projects would need to be viable.

Small-scale electrical and thermal storage

57.Lithium-ion batteries, the technology used to power many portable electronic devices and Electric Vehicles (EVs), are falling in cost and could have network applications. Other battery technologies of note include lead-acid and sodium-sulphur. Flow batteries, which store energy in liquids, are an alternative to conventional batteries. Hydrogen fuel cells can work like batteries and play similar roles, but are replenished through a fuel source (hydrogen) rather than recharged with electricity. Flywheels—which charge and discharge by spinning—and supercapacitors (high-capacity electrochemical capacitors) are fast to respond but have limited capacity, compared to batteries.131

58.Battery costs are dropping, but remain high relative to generation.132 Chris Morrison, Head of Energy Construction Services for Centrica’s Distributed Energy and Power group, noted that an “increase in capacity of supply for batteries will lead to significant reductions in cost and we are already starting to see costs fall very quickly on batteries”.133 Other stakeholders agreed that batteries, particularly lithium-ion, were the storage technology most able to be rolled out with scale and pace.134 Dr Philipp Grünewald, Research Fellow at Oxford University’s Environmental Change Unit, giving evidence on behalf of the Institution of Civil Engineers (ICE), made the important observation that the efficiency of a storage technology in isolation may not accurately reflect the improvement it can make to system-wide efficiency.135 However, he also likened the lithium-ion battery to a “Porsche”, stating that “what we need for grid service is a bit like delivering gravel, and what we are proposing to do with lithium-ion batteries would be like delivering gravel with a Porsche, whereas in fact we need lorries”;136 he clarified that PHS was the “lorry” in this metaphor.137

59.We heard mostly about electricity storage, but also that heat storage is an important option. Dr Tim Rotheray of the ADE noted that “thermal storage costs about 100 times more than storing fuel in tanks and so forth. Electrical storage costs 100 times more again, so 10,000 times more than storing [fuel]”.138 Dr Jill Cainey observed:

There are 14 million system boilers with hot water tanks in the UK. Those hot water tanks with immersion heaters represent a huge source of flexibility, yet we tend to be ripping those system boilers out and replacing them with a different type of boiler. Additionally, there are electric hot water tanks and households with just electricity heating with immersion heaters. Again, that is another significant source of system flexibility that we could look at now.139

Scott Mathieson of SPEN concurred that storing heat in immersion heaters was “a more readily available technology” and “more cost effective potentially” than domestic batteries.140

Storage regulation

60.The glacial pace with which regulation is adapting to storage may be a greater impediment than any technological immaturity: overcoming regulatory barriers to storage has become a dominant theme of this inquiry. The REA observed that “energy storage technologies (batteries and pumped hydro for example) have been around for decades in the UK but require an appropriate policy framework to deliver”.141 Phil Sheppard of National Grid emphasised the importance of this work:

I was at a carbon-limiting technology conference that DECC was hosting with investors and developers, and the No. 1 thing—immediately after predictability of policy—was changing the rules on storage or clarity on how storage is going to be treated from a regulatory and policy perspective.142

61.The ICE observes two regulatory barriers to storage deployment. Firstly, storage is classified and licensed as generation: this limits network companies to operating no more than 100 megawatts (MW) of storage.143 Secondly, storage is liable for BSUoS charges, which they are charged twice—once for ‘consuming’ the electricity they store, then for supplying it back to the grid—costing UK storage approximately £14.9 million annually.144 They are also double-charged the Climate Change Levy (CCL).145 Storage helps system balancing rather than the opposite; we find it odd that these charges are levied at all, let alone twice. Drs Edge and Cainey further noted that storage being classified as ‘demand’ and as ‘generation’ subjects it to two different connection regimes and charging methodologies.146 These barriers all flow from storage’s classification as generation; creating a new, distinct, asset class may therefore solve them. Dr Cainey described the classification as “an accident of history”.147 Scott Mathieson also considered this a “strange anachronism”.148 Government has been slow to address this ‘accident’; Dr Cainey further noted there had been no individual responsible for storage policy at DECC during the last Parliament.149

62.The Government told us it is now looking at storage. Lord Bourne of Aberystwyth, Parliamentary Under-Secretary of State for Energy and Climate Change, recently stated:

In relation to storage, if we are talking battery storage here, this is something clearly of great significance. The Department is working very hard on this across Government, with DfT in particular; it has issues. We are aware of the potential. It is not oven-ready for legislation yet but it is something that we are working up. Within this Parliament certainly, and I hope earlier rather than later, we will be doing something on this.150

He added that such legislation would be “not for the [2016–17 Parliamentary] session”.151 In April 2016, Andrea Leadsom MP, Minister of State for Energy and Climate Change, noted that DECC was “literally about to publish a call for evidence on smart systems”152 and that “there is an enormous urgency in DECC to resolve the issues for storage”.153 Despite this professed urgency, we are at time of writing still awaiting the launch of this consultation. Ofgem committed in September 2015 to “clarify the legal and commercial status of storage” over the next year.154 The National Infrastructure Commission (NIC) recommended that “DECC and Ofgem should review the regulatory and legal status of storage and remove outdated barriers [ … ] the reforms should be proposed by Spring 2017 and implemented as soon as possible thereafter”.155 The Government has accepted this recommendation.156 However, when questioned, it did not wish to commit to a more precise timetable for advancing storage regulation.157

63.Andy Burgess of Ofgem told us “defining [storage] as a specific asset class might be the answer, but from the analysis we have done so far that is not the immediate solution”.158 He expounded on the difficulties of this approach:

If you create a new licence, then it is a question of what goes with that licence. You would need to amend primary legislation to create a new licence category. We would need to check that whatever we were doing was consistent with wherever European law was going, because storage is quite an important issue at European level.159

He did not think the same problems applied to a modified generation licence.160 We asked the Minister about changing the licensing for storage, which appears a straightforward approach. She noted “that is absolutely one answer but it is not the quick and easy solution that some might think because it would require massive changes to network codes, which could themselves take two or three years.”161 She announced that the upcoming consultation would seek a speedier approach.162

64.The current regulatory conditions for storage are hindering its development. We welcome the Government’s consultative approach to this matter, but hope it will proceed with a sense of urgency. We urge the Government to publish its plans, as soon as possible, for exempting storage installations from balancing charges, and from all double-charging of network charges.

65.There has also been debate about the role of network companies regarding storage: should they own, operate, install and utilise storage? We take these terms to mean the following:

Stephen Goldspink of Siemens Energy Management argued “allowing DNOs to install, operate and utilise storage would be a really positive step”.163 The REA called for “energy storage technologies to be operated and owned by DNOs”;164 the Power Systems Group at Newcastle University made a similar contention.165

66.However, not everyone was convinced that DNOs should have a major role in owning and operating storage. Chris Morrison argued “the DNO and the DSO166 would be a monopoly provider in a certain area and, while they would be procuring solutions for flexibility and management of the grid, it is important that we have an open and competitive framework that allows everyone to participate in the procurement of those services”.167 Andy Burgess warned of dangers:

Our principle is that we want to see competitive markets develop—generally competitive markets and flexibility—and storage is part of that. Procuring storage is fine, and using storage is fine. Owning and operating storage immediately raises some issues about whether you can develop a natural competitive market for storage if you allow natural monopolies, particularly with regulated income, to start playing in those markets. Therefore our principle is that the network companies should not own or operate storage. We recognise there might be some exceptions to that based on particular circumstances or needs, or where you define storage as something where you just could not develop a competitive market. However, we think if you want competitive markets to develop it is important to keep the regulated monopolies out of them.168

67.Storage technologies should be deployed at scale as soon as possible. We support network utilisation of storage: this helps balance the system, and provides storage operators with a revenue stream that encourages its development. Allowing networks to operate and procure storage, especially in the short run, could also facilitate these benefits. However, we have concerns about network ownership of storage. In the long run, we do not want networks to have vested interests in particular technologies that discourage them from switching where more cost-effective solutions emerge; we are also concerned about any expansion of networks’ monopoly power more generally. DECC and Ofgem should analyse the long-term risks of network ownership, operation and procurement in their work on storage.

Demand Side Response

68.Demand Side Response (DSR) denotes mechanisms by which electricity users can be encouraged to reduce their consumption at specific times: this is particularly useful at times of narrow system margin. From a system perspective, widespread DSR would make energy demand more flexible. The system could be balanced by curtailing consumption rather than firing up reserve generation. It has been estimated that expanding DSR could reduce electricity system costs by 10%, annual transmission-network investment by £800 million and peak generation capacity by £266 million.169 There are three major types of DSR:

Note that on-site generation is occasionally considered a type of DSR: a factory with a diesel generator can reduce the demand it places on networks by running that generator. Whether or not this is DSR, it is unlikely to be low-carbon, and we do not consider it here.

69.Dr Philipp Grünewald described DSR as “the least well understood” of major options for balancing the system.170 Individual load-shifting requires consumers to have an incentive to use energy at off-peak times. However, suppliers do not have access to consumers’ half-hourly data without smart-meters, and cannot reward them for using electricity at cheaper times. Half-hourly settlement, where actual half-hourly data (rather than estimated usage patterns) determines what suppliers pay for electricity, could create an incentive for them to encourage their customers to shift loads. They could do so by offering Time of Use (ToU) tariffs, where consumers pay different energy rates at different times of the day.171 Asked to suggest regulatory changes to bring DSR forward, Sara Bell, CEO of Tempus Energy, told us her “No. 1 ask would be half-hourly settlement of all customers as quickly as possible”.172 The Government plans to introduce elective half-hourly settlement in 2017, and will consider making it mandatory thereafter.173 Our recent pre-legislative scrutiny of the Government’s draft legislation on energy considered half-hourly settlement in greater detail.174

70.Stephen Goldspink told us the smart meter roll-out “kick-starts this whole behavioural change within the UK”.175 Dr Philipp Grünewald was more sceptical as to the powers of smart meters to trigger behavioural change, noting “there is the neo-classical approach—that we just set a price signal and they will respond—but there is also a school that says these behaviours are more complicated and deserve more scrutiny to understand what triggers flexibility on the demand side”.176 We learned in Copenhagen that Denmark is currently rolling out smart meters, and has already installed 2 million. These are owned by the distribution networks and feed information to a central data hub at Denmark’s TSO, Energinet.dk. However, Denmark has so far seen little evidence of individual load-shifting; it was felt that greater use of smarter, automated appliances may be needed for this.

71.Aggregators can be better placed than lone individuals to untap load-shifting potential: they “coordinate groups of end users who are able individually to offer only small amounts of demand flexibility, combining these into more substantial reductions in demand which they can sell” and “cover the risk of not delivering this flexibility”.177 However, the National Infrastructure Commission (NIC) notes that “aggregators are unable to access the UK’s electricity markets on equal terms with generators” as “there is no defined role for third parties” in the balancing market (where the TSO micro-manages electricity supply and demand into balance in the immediate run-up to real time).178 This denies the TSO a tool for balancing the system.

72.DSR can be traded in the Capacity Market, an auction system designed to improve security of supply. However, KiWi Power, a DSR provider, argued that “the UK market has not provided a level playing field between supply and demand, with the first Capacity Market auction resulting in just 0.3% participation from DSR” and that “biases towards generation exist in the [Capacity Market] design, such as the ability for generators to tender for 15-year contracts while DSR is only able to tender for 1-year contracts”.179 Tempus Energy claimed that “the UK capacity market presents a huge missed opportunity for energy intensive industries and innovators to come together”.180 Our predecessors raised these concerns with DECC last year.181 In response DECC told us that:

Analysis of currently-available evidence indicates that DSR and existing generation do not require such significant up-front capital investment, which would potentially necessitate access to long-term capacity agreements. In fact, current evidence suggests that DSR is a relatively low-cost solution and should therefore be able to compete effectively on the basis of one-year agreements.182

73.Citizens Advice, a consumer watchdog, identified risks to consumers from the increasing complexity of DSR:

The two main issues raised by DSR are first that it could complicate an already over-complicated market, meaning some consumers end up on unsuitable deals without due protection; and second that it could create a two-tier market of flexibility haves and have-nots, where those who cannot shift their usage do not receive any of the benefit from overall system efficiency.183

74.The NIC recommends that “Ofgem should start an immediate review of the regulations and commercial arrangements surrounding demand flexibility with a focus on making participation easier and clarifying the role of aggregators”.184 The Government has committed to undertaking this work, “through the forthcoming call for evidence on a smart systems route map” (referred to in paragraph 62), by Spring 2017.185

75.The promised review of Demand Side Response (DSR) by Ofgem is a sensible first step towards clarifying and unlocking the potential for DSR technologies and business models. However, we maintain the views of our predecessor Committee that the Government needs to set out a more detailed strategy for DSR. This strategy and any work on this issue by Ofgem must also pay close attention to the risks of DSR for vulnerable customers, and how best to mitigate these.


76.Interconnectors are transmission lines that connect one country’s transmission system to another, allowing for import and export of electricity or gas: we focus here on electricity. They earn revenue from arbitrage—buying electricity from the country in which it is more expensive, and selling to the other. Interconnectors help balance the system both by effectively counting as extra generation capacity (electricity can be imported to make up any shortfall on one side) and by providing emergency services to the TSO.186 Ofgem’s Cap and Floor (CaF) regime sets interconnectors’ upper and lower revenue limits, though some interconnectors (such as BritNed and ElecLink) choose to operate without a CaF.187 Informal discussions with engineers in Copenhagen suggested that 2 GW is the upper limit on the capacity of a single interconnector.

77.In 2014, wind provided for 39.1% of Denmark’s electricity needs.188 As wind is variable, this is an average: the proportion varied between 0% and 132% in 2014.189 Energinet.dk, the Danish TSO, has retained a secure supply, with only 41 seconds of electricity outage last year.190 We learned, when visiting Copenhagen, that Denmark’s high level of interconnection—its import capacity represents 85% of its peak demand—191is key to this management. As EDF Energy pointed out, the UK has comparatively “greater costs to ensure interconnection” than other EU countries;192 yet the value of interconnection in balancing variable generation should not be underestimated.

78.The GB transmission system is currently linked to those of Ireland, France and the Netherlands. Charlotte Ramsay, Head of Strategy Markets and Regulation at European Business Development, a National Grid subsidiary focused on interconnection, said “at the moment we are not very heavily interconnected”, noting 4 GW of current interconnection and “between 9 and 11 GW being on stream by the early 2020s”.193 The table below describes GB’s current and planned future interconnection:

Table 1: Current and future UK interconnection





UK owner



1 GW


National Grid



0.5 GW





2 GW


National Grid



0.5 GW


Mutual Energy



1 GW


Star Capital Partners

FAB Link


1.4 GW

CaF approved

Transmission Investment



0.5 GW

CaF approved

Element Power



1 GW


National Grid



1 GW

CaF approved

National Grid

Nemo Link


1 GW


National Grid



1.4 GW


National Grid

Viking Link


1.4 GW

CaF approved

National Grid

Sources: Q237 [Charlotte Ramsay]; Elexon, Interconnectors, accessed 13 June 2016; National Grid, Interconnectors, accessed 13 June 2016; Ofgem, Electricity interconnectors, accessed 13 June 2016

The table shows that up to 8.7 GW of new interconnection is planned. The Government “supports the market delivery of at least 9GW of additional interconnection capacity”.194

79.We heard that Ofgem’s cap and floor regime is “an open and competitive process”.195 The ENA “are in the early stages now of forming an interconnectors forum”.196 Be that as it may, a glance at the table above reveals that National Grid continues to dominate this market. We would like to see greater competition for new interconnector developments in the future, particularly given potential conflicts of interest relating to National Grid’s interconnector holdings, which we return to in chapter 4.

80.We discussed Viking Link, the proposed GB-Denmark interconnector, during our visit to Copenhagen. Scientists from the Technical University of Denmark (DTU) noted that GB and Denmark tend to be windy at different times: we later heard, from Danish energy experts, that Viking Link could therefore combine GB and Danish wind into ‘virtual baseload’ with high reliability. We also noted that due to existing interconnection between Denmark and Norway, Viking Link would give the UK an indirect link to Norwegian hydropower.

81.The NIC recommends that Government “focus its efforts on exploring increased interconnection to markets with abundant sources of flexible low carbon electricity, such as Norway and Iceland.”197 Aurora Energy Research, a consultancy, is more critical of building interconnectors. It cites “significant costs […] big enough to make the net GB welfare impact of most new interconnector projects negative” with the exception of Norway.198 Aurora argues that interconnectors have a net negative effect on CO2 emissions, as they create bigger demand peaks in export countries (thus incentives for fossil-fuel generation).199 It contends that “the fundamental economics of interconnection dictate that GB is likely to be a net importer of electricity from European markets”.200 In response to Aurora’s research, the Minister argued Aurora “seem to have overestimated the downside and underestimated the positives” and that “Ofgem does its own very thorough cost-benefit analysis, taking into account the energy trilemma”.201 She also noted “we tend to receive electricity rather than export it, but that does not make us a net importer”.202

82.Significant interconnector expansion will help balance a low-carbon network, and we support it for that reason. We note that Great Britain is likely to be a net importer of electricity; development of interconnection should be accompanied by a strategy to develop sufficient low-carbon generation capacity for export.

83.The NIC highlights “a role for government-led diplomacy to unlock those markets that can offer potentially large benefits to UK consumers”.203 Charlotte Ramsay stated that “Government have already been very helpful in this space”, noting that “with a lot of the countries that [National Grid] connect to, the decision making around whether or not you build an interconnector and how you connect two markets rests with the Government rather than with the regulator”.204 The Minister added that “whenever a Foreign Office Minister or another Minister is travelling somewhere that could have useful energy interests communicated, then we always make sure that is included in their brief as a point to raise”.205 We welcome this approach, and encourage the Government to continue diplomatic efforts to develop interconnection.

84.Interconnectors are traditionally a direct link between two countries fed into by pre-existing sources of generation. However, we have come across different business models in the course of this inquiry. IceLink, the proposed GB-Iceland interconnector, was described as “something of a special case, because it does not have the same business case or commercial case as a traditional point-to-point interconnector.”206 The NIC elaborates that “the overall project is likely to require a package of new generation along with the interconnector”.207 Charlotte Ramsay added that an intermediary connection to the Faroe Islands was “part of the discussion” around IceLink.208 She noted that IceLink’s first milestone to achieve would be a Government-to-Government agreement between GB and Iceland.209 The project was “a definite possibility” but also “high-risk”:210 it would, after all, be the longest subsea cable in the world.211 The Prime Minister has established a taskforce looking at IceLink.212

119 DECC, DUKES, Electricity fuel use, generation and supply (DUKES 5.5), July 2015

120 Intermittent Electricity Generation, POSTnote 464, POST, May 2014, p1

121 Q32

122 International Energy Agency (IEA), Technology Roadmap: Energy storage, 2014, pp16–17

123 DECC, DUKES, Electricity fuel use, generation and supply (DUKES 5.5), July 2015

124 Engie, First Hydro, accessed 13 June 2016

125 Energy Storage, POSTnote 492, POST, April 2015, p2

126 Gaelectric, Project-CAES Larne, NI, accessed 13 June 2016

127 Q54

128 Q54

129 Q227 [Phil Sheppard]

130 Q307

131 Energy Storage, POSTnote 492, POST, April 2015, p2

133 Q7

134 Qq61–4 [Dr Cainey and Dr Grünewald]

135 Q42

136 Q55

137 Q58

138 Q154

139 Q65

140 Q9

141 REA (LCN0033)

142 Q229

144 ICE, Electricity Storage: Realising the Potential, October 2015, pp13–14

145 Q74 [Dr Cainey]

146 Q77

147 Q71

148 Q19

149 Qq72–3

150 Energy and Climate Change Committee, Oral evidence taken on 22 March 2016, HC (2015–16) 776, Q187

151 Energy and Climate Change Committee, Oral evidence taken on 22 March 2016, HC (2015–16) 776, Q188

152 Q302

153 Q313

155 National Infrastructure Commission, Smart Power, March 2016, p11

156 HM Treasury, Government response to Smart Power, April 2016, p2

157 Q312 [John Fiennes]

158 Q259

159 Q259

160 Q260

161 Q302

162 Qq310–11

163 Q75

164 REA (LCN0033)

165 Newcastle University (LCN0034) para 13

166 Distribution System Operator

167 Q23

168 Q261

169 Electricity Demand-Side Response, POSTnote 452, POST, January 2014, p4

170 Q81

171 Ofgem, Elective half-hourly settlement: conclusions paper, May 2016, paras 1.1–1.7

172 Q91

173 Q323 [John Fiennes]

174 Energy and Climate Change Committee, Sixth Report of Session 2015–16, Pre-legislative scrutiny of the Government’s draft legislation on energy, HC 776, paras 30–31

175 Q89

176 Q82

177 NIC, Smart Power, March 2016, p51

178 NIC, Smart Power, March 2016, p54

179 KiWi Power (LCN0053)

180 Tempus Energy Supply (LCN0056)

181 Energy and Climate Change Committee, Eighth Report of Session 2014–15, Implementation of Electricity Market Reform, HC 664, para 38

182 DECC, Government Response to the Energy and Climate Change Committee Report on the Implementation of Electricity Market Reform, Cm 9090, June 2015, p6

183 Citizens Advice (LCN0013), para 20

184 NIC, Smart Power, March 2016, p59

185 HM Treasury, Government response to Smart Power, April 2016, p3

186 Energy and Climate Change Committee, Oral evidence taken on 24 November 2015, HC (2015–16) 509, Q55 [Duncan Burt]

187 Ofgem, Electricity interconnectors, accessed 13 June 2016

188 Energinet.dk, Annual report 2014, April 2015, p10

189 Energinet.dk, Annual report 2014, April 2015, p23

190 Energinet.dk, Annual report 2015, April 2016, p8

191 Energinet.dk, Annual report 2014, April 2015, p15

192 EDF Energy (LCN0027)

193 Q252

194 HM Treasury, Government response to Smart Power, April 2016, p1

195 Q244 [Charlotte Ramsay]

196 Q244 [Tony Glover]

197 NIC, Smart Power, March 2016, p34

198 Aurora Energy Research, Dash for interconnection, February 2016, p2

199 Aurora Energy Research, Dash for interconnection, February 2016, p7

200 Aurora Energy Research, Dash for interconnection, February 2016, p8

201 Q337

202 Q339

203 NIC, Smart Power, March 2016, p34

204 Q241

205 Q343

206 Q238 [Charlotte Ramsay]

207 NIC, Smart Power, March 2016, p3

208 Q245

209 Q238

210 Q238 [Charlotte Ramsay]

211 Q343 [Andrea Leadsom MP]

212 Qq340, 343 [Andrea Leadsom MP]

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15 June 2016