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

3 Transforming transmission

39.  Because we do not know yet what the energy mix of the future will look like, neither do we know with any certainty how the transmission network will evolve. We have already identified, however, that there is a risk of continuing Britain's 'lock-in' to a 'big' transmission system if the regulatory framework does not allow for the possibility of other outcomes. In this Chapter we consider a range of issues that have concerned policy-makers in recent years in determining transmission policy.

Investing in capacity

40.  Ownership and operation of the transmission networks in Britain is permitted under licence, the terms of which restrict the revenue of the licensed network businesses.[53] The revenue allowed to transmission companies is based on a pre-determined programme of investment agreed between them and the regulator. It is reviewed every five years by Ofgem through what is known as a Transmission Price Control Review (TPCR). The current TPCR period runs from 2007 to 2013, having recently been extended by one year. In 2009/10 it will allow companies to recover around £1.5 billion in revenues. For households, the cost of transmission equates to around 4% of electricity bills.[54] Growth in companies' revenues is determined using the RPI-X framework. This approach has encouraged firms to reduce costs over time through efficiency improvements. The next TPCR will be based on a new regulatory framework, arising from the current RPI-X@20 review.

41.  Ongoing investment in the transmission network is necessary to ensure the system remains operational, for example, through the replacement of ageing or obsolete assets. It is likely that a system of balancing supply and demand such as BETTA will continue to operate in the longer term, and therefore new investment will also be crucial to assist with the migration of less efficient and older plant towards a marginal supply position on the basis of continued availability as installed capacity. However, many within the industry now argue that further investment to expand the system is required in order to connect the expected growth in renewable generation in the coming years. In this section we look at the main barriers to expansion of the transmission network and the case for further investment.


42.  The planning system is a fundamental determinant of whether investment in new transmission capacity is delivered on time, and was highlighted as a potential barrier by the Department, the regulator and the industry.[55] Past experience explains why this is the case. In the 1990s it took over six years to acquire planning consent for a 50-mile stretch of new high voltage power lines in North Yorkshire.[56] More recently, the upgrade of the 137-mile line between Beauly near Inverness, and Denny near Falkirk, replacing the existing 132 kV cables with high voltage 400 kV lines, entered the planning system in 2005. Seen as key to allowing the connection of new onshore wind farms in northern Scotland, the project was first conceived in 2001, and awarded funding by Ofgem in 2004. Consent was finally granted in January 2010, which means construction work could be completed by 2012, when projects would be able to connect to the new line. From conception to completion, the upgrade will have taken 11 years.[57] Smaller projects have also faced difficulties. Scottish Power told us about a 20 km wooden pole line it wished to build between Lostock and Carrington in Lancashire.[58] The company submitted its planning application in 2003, but is not expecting to receive consent until later in 2010.

43.  Overall, many of our other witnesses were highly critical of the planning process. The Scottish Chambers of Commerce described it as "sclerotic".[59] Another witness said that, left unaddressed "the planning system is likely to thwart aspirations for connecting renewable generation".[60] Elsewhere, Scottish and Southern Energy told us: "The shortcomings of the planning systems need to be addressed if the UK is to meet the EU 2020 target and longer-term security of supply and climate change goals".[61]

44.  Several organisations, however, sought to defend the planning system. Scottish Natural Heritage, for example, told us the length of inquiry into the Beauly-Denny line was partly the result of the transmission companies having not undertaken sufficiently thorough exploration of alternative options, such as burying cables underground in areas of environmental sensitivity.[62] The Campaign to Protect Rural England (CPRE) noted that the delay to consenting the North Yorkshire line had been the result of the developer having to consider ways of lessening the impact of the line on the landscape that it had not fully addressed in its initial proposal.[63] Both organisations rejected the idea that the planning process should be considered a 'barrier' to network expansion—rather, as CPRE told us: "it is a vital means of ensuring that the future development of the transmission network takes full account of the public interest".[64]

45.  In order to address some of the concerns with the current planning system, the Planning Act 2008 established an independent Infrastructure Planning Commission (IPC), which will operate a streamlined consenting process. Under the new arrangements Ministers will retain responsibility for the policy framework, which will be set out in National Policy Statements (NPSs). The IPC will make decisions on consents based on these NPSs, which will set out the need for the infrastructure and how the IPC should consider impacts. Consultation on applications will be required before they are submitted to the IPC, and guidance given on what constitutes a good application. The hope is that this will mean the Commission can consider applications more quickly, which it will do within set timetables.[65] The Government published the draft NPS on electricity networks infrastructure in November 2009, as part of a suite of energy NPSs.[66] They are subject to consultation and parliamentary scrutiny, for which this Committee is playing a key role, before likely designation sometime in 2010.

46.  Only planning applications for power lines in excess of 132 kV, or network infrastructure that is associated with a nationally significant power station, will be subject to approval by the IPC. This means that consenting for lower voltage distribution lines will still fall to local planning authorities. The new system applies only to England and Wales. In Scotland, reform has also taken place: measures announced in 2008 include the requirement for promoters of major developments to conduct a consultation with the community before submitting the planning application. A statutory four-month time period for a decision on applications will also be put in place. Other reforms in Scotland include: simpler and more transparent processes; quicker decision-making by councils on high-quality applications; a greater focus on matters of national interest; and up-to-date development plans to provide investors and communities with greater certainty. In 2009 the Scottish Executive also published its second National Planning Framework (NPF2), which designated 14 national developments of strategic importance to Scotland, of which electricity grid reinforcements was one.

47.  The network industry broadly welcomed reform of the planning system.[67] There is a high level of expectation on the ability of the changes to speed up the planning process. E.ON UK told us: "The success of the new IPC planning process […] will be key to the delivery of major infrastructure projects".[68] Scottish and Southern Energy said: "The importance of the National Policy Statements cannot be overemphasised […] the NPSs must be clear and have sufficient depth to form the basis for authoritative decisions".[69] The Association of Electricity Producers noted its concern, though, that there remains a disjointed approach between the systems in England and Wales and Scotland, with varying timescales, considerations and processes. It believed greater consistency was needed.[70]

48.  Reform of the planning process is vital if network improvements are to be delivered on time to connect new generating capacity in the future. We note the recent changes to the planning systems in England and Wales, and Scotland, and are pleased to be playing a role in scrutinising the draft National Policy Statement for Electricity Networks Infrastructure. We hope the new system will lead to a faster decision-making process, but one that nonetheless will take account of the environmental concerns associated with new proposals. For this, developers have a duty to ensure their initial applications take adequate account of alternative options. The Government should also look closely at the consenting process for applications in England and Wales that will not fall to the Infrastructure Planning Commission to see whether reform or improved guidance is necessary at this level as well.


49.  Under the existing TPCR framework investment is reactive—transmission companies do not undertake reinforcement or line extension work until individual generating companies have guaranteed they will meet the cost of those connections.[71] This approach, whereby network capacity is expanded only if there is a power plant ready to use it, has helped reduce the risk of investment capacity not being utilised, otherwise known as stranded assets.[72] However, this can cause problems for generating companies that are not able to guarantee their connection until they are confident their projects will proceed, for example, once they have received planning permission. We have already seen, though, that the consenting process for new grid capacity can take time. This can lead to a mismatch between when a project is ready to connect to the grid, and when the grid capacity is available to connect it. The problem is exacerbated by the fact that, as the share of renewables in the electricity mix expands, transmission reinforcement is being driven increasingly by a large number of relatively small projects.[73]

50.  The existing regulatory framework is now affecting the ability of transmission owners to provide connections in the necessary locations.[74] For example, National Grid told us: "A more flexible mechanism is required to deliver the infrastructure investment in our vision".[75] This would also align better the construction programmes of the transmission companies and power station developers. Accordingly, a consensus has emerged within the industry in support of strategic investment in grid capacity—that is, investment ahead of individual projects being able to give specific financial commitment for their connections.[76] This is possible because the general geographical location of a significant amount of future renewable generation, particularly wind power, is already well known.

51.  To identify where areas of investment were required, in 2008 Ofgem and the Government asked the Electricity Networks Strategy Group (ENSG)—a senior industry group—to consider what the transmission system would need to look like to meet the 2020 targets for renewable energy. The ENSG published the first phase of its work in March 2009. It identified reinforcement work for a range of projects in areas of Scotland, Wales, East Anglia, London and the South West. It includes potential high voltage subsea cables between Scotland and the north of England along both the east and west coasts. In total, the work could amount to £4.7 billion between now and 2020. This is in addition to network investments already approved to connect renewable generation and through the current transmission price control. Combined, the cost of this work would be equivalent to the asset value of the existing transmission system—potentially the biggest grid development since the Second World War.[77] It is also worth noting that this excludes the cost of connecting future offshore wind. The report notes that provided the work is taken forward in a timely manner, subject to planning consent, the reinforcements could be delivered within the required timescales. They would be phased over the next decade with the resulting network able to accommodate between 29 and 45 gigawatts of new generating capacity.[78]

52.  The ENSG work has received widespread support from the industry.[79] E.ON called for transmission companies to be permitted immediately to commence with pre-construction work for the projects identified.[80] Scottish Renewables said: "It is important […] that work on these upgrades and reinforcements should start as quickly as possible".[81] Ofgem responded in April 2009 by approving up to £12.5 million of funding outside the current TPCR for the transmission companies to begin feasibility studies and preparatory work. Since then the regulator has been working with the firms to establish longer-term funding arrangements that will facilitate a programme of strategic investment. In January 2010 the regulator approved additional funding of up to £1 billion for construction work on specific projects.[82] Further investment will be funded through the next TPCR, due to begin in April 2013. A key part of Ofgem's work will be to ensure that additional funding does not lead to the construction of unused, stranded assets. In its evidence to us the regulator acknowledged that its new approach entailed making a judgement on the level of stranded asset cost that was reasonable to incur for consumers, and that this represented "a fundamental philosophical shift" in its regulation of network investment.[83]


53.  Although there was a consensus between the generators and network companies in favour of significant new investment in transmission reinforcements, this view was not shared by all who gave evidence to the Committee. For example, Dr Michael Pollitt told us a key concern should be "making sure that we do not […] give network incumbent companies a licence to massively increase capacity, which might not be necessary".[84] Prof Strbac noted too that the ENSG work presents a solution that involves a 'business as usual' response by the industry that is a direct consequence of the existing regulatory framework.[85] Although both acknowledged that investment in the network infrastructure will be needed, they also believed that, in addition to new capacity through network reinforcements, a range of other solutions that can release latent network capacity should also be considered. These include, for example, the application of a variety of operational measures, emerging local generation coming on stream, or allowing a greater role for responsive demand—all of which could substitute for network investment.

54.  A further important concern raised by Phil Baker and Dr Bridget Woodman at the University of Exeter was that existing network assets should be fully utilised before making the case for further investment.[86] The GB Security and Quality of Supply Standards (SQSS) set out the criteria and methodologies that National Grid must use in the planning and operation of the electricity transmission system. In other words, they determine the level of transmission asset utilisation. Baker and Woodman told us there is scope to improve the utilisation of the existing transmission assets.[87] One example could be a move towards weather-related security standards. At present around 70% of transmission faults relate to weather conditions. However, the weather is not taken into account when operating the transmission system, even though it may be possible to relax operational security standards during fair-weather conditions, and so release latent network capacity. Such an approach could significantly decrease the external costs of operating the transmission system and reduce the need for investment without posing a risk to customer supplies.

55.  Another way of releasing latent capacity from the existing network is through the use of special protection schemes. These are intelligent tripping systems that mitigate unexpected faults that could lead to a disconnection of a transmission line by automatically tripping generation or shedding demand load from elsewhere on the system. Although limited in scope at present, network operators already use some of these technologies to enhance the capability of their existing systems. Worldwide, there is growing interest in the development and application of such approaches, which entail more sophisticated system operation, but also minimise or avoid the need for network reinforcements. Solutions such as special protection schemes are more widely used in other parts of the world, including the US, Brazil, Chile, Australia and Taiwan, thus allowing system operators to achieve a higher level of network utilisation.

56.  Prof Goran Strbac argued that the SQSS, which have remained largely unchanged since 1948, present a barrier to a range of other solutions that could release latent capacity from the existing network.[88] Among others, these include more sophisticated system operation, such as the application of advanced network control, protection and maintenance techniques and innovative decision-making tools.[89] They also include non-network solutions such as the greater role of demand in managing the electricity system as discussed in Chapter 2. This is important because these alternative approaches could not only enable the release of latent capacity from the existing transmission assets and facilitate the connection of greater amounts of wind power in the short term, but also in the longer term play a key role in the development of a smart grid.

57.  Phil Baker and Dr Bridget Woodman also criticised the incentives in place for new transmission capacity.[90] At present the regulated income of transmission operators through the transmission price control review (TPCR) is a function of the value of their asset base. This, therefore, places an incentive on companies to grow that base by building as much transmission capacity as they can justify, rather than actively looking for operational alternatives. In June 2008 the transmission companies began a fundamental review of the SQSS. This could provide a major opportunity to reform the Standards to maximise utilisation of the existing network and encourage the take-up of smart grid technologies. The review team's terms of reference set a target date of September 2009 to report and consult on detailed proposals.[91] These have not yet been published. We note that the ENSG work that proposes significant strategic network investment is based on the existing SQSS.

58.  To avoid delays in connecting new power stations a more strategic approach to investment in transmission capacity is necessary. We welcome the Electricity Networks Strategy Group's work to identify the reinforcements it believes are needed in the next ten years. We also note Ofgem's cautious approach in allowing funding to advance particular projects and we urge them to be more proactive in promoting ways of avoiding delays.

59.  Given the costs involved, the resulting impact on customers' bills, and the risks of delay, it is vital the case for investment is as robust as possible and preferable to any alternatives. There is some concern that the existing regulatory framework is driving the case for transmission investment presented by the industry at the expense of other more cost-effective options that seek better to utilise the existing network infrastructure. The current fundamental review of the Security and Quality of Supply Standards (SQSS) presents a major opportunity to address these issues. However, the review, which had aimed to publish detailed proposals in September 2009, has not yet reported. Therefore, we are concerned that some of the currently proposed strategic network investment that is based on the existing SQSS may prove unnecessary. Furthermore, reform of the SQSS will be vital for the development of a future smart grid. It would be totally unacceptable if Ofgem failed to fulfil its duties to consumers by not ensuring the timely completion of this review, especially as the regulator has already begun to grant funding for additional investment. We consider it essential that consideration of new investment in transmission has the benefit of the outcome of the SQSS review and strongly recommend that urgent measures are taken to complete and publish the review.

Network charging

60.  On connection to the GB transmission system, generators are required to pay the following charges:

  • Connection Charges: These enable National Grid to recover the costs involved in providing the assets that allow connection to the transmission system.
  • Balancing Services Use of System (BSUoS): This charge recovers the cost of balancing demand and supply across the system.
  • Transmission Network Use of System (TNUoS): This charge recovers the cost of installing and maintaining the transmission network required to allow the bulk transfer of power between sites and to provide transmission system security.[92]

In this section we focus on current issues concerning the second and third of these charges.


61.  The transmission system has a finite capacity to transport electricity between power stations and consumers. Constraints can occur when the system is unable to transmit the power supplied at a particular location to where demand for it is situated. This may be because heating ratings on electricity lines have been exceeded, or because of an inability to maintain voltages on the system within the limits set out in the GB Security and Quality of Supply Standards (SQSS) discussed in the previous section. Constraints can also be exacerbated by transmission outages arising, for example, from network reinforcements, or unexpected generation failure. When such constraints occur National Grid, the system operator, will take action to reconfigure the system and/or go to the wholesale electricity market to increase or decrease the amount of electricity being supplied to the system at different locations.[93] If National Grid has to require a power station to reduce its output because of constraints on the transmission network, the generator is compensated for the reduction in the grid's capability to take their full output. The costs incurred are referred to as constraint costs. Along with all the other costs associated with keeping the system in balance and maintaining security of supply, these are passed onto users of the system through Balancing Services Use of System (BSUoS) charges. They are paid equally by generators and consumers, and do not vary by location.

62.   In recent years the level of constraint costs have risen from £70 million in 2007/08 to £262 million in 2008/09 and are forecast to be £198 million in the current financial year.[94] Constraint costs have caused growing concern for Ofgem since the establishment of the British Electricity Trading and Transmission Arrangements (BETTA) in 2005. The Arrangements brought together the electricity markets for Scotland, England and Wales. Under the regime, generators self-despatch their plant. In other words, they have guaranteed access to the grid, except at times when they are constrained off by the system operator. Because the interconnection between England and Scotland, known as the Cheviot Boundary, does not have the capacity to always meet the demands placed on it by electricity flows between the two countries, Ofgem has issued the boundary a derogation from the requirement to comply with the Security and Quality of Supply Standards (SQSS).

63.  Constraint costs are key to informing investment decisions in new network capacity.[95] Accordingly, an investment programme is underway to upgrade the Cheviot Boundary as this is seen as a main pinch-point on the network. It is important that constraint costs send the right signal of investment needs. The evidence we received suggest two factors have contributed to the level of these costs being higher than they otherwise could be—the inherent nature of BETTA and the alleged exploitation of market power by the Scottish transmission companies.

64.  One of the key differences between the BETTA system and the electricity 'Pool' trading arrangements that preceded it is that the market does not explicitly reward companies for providing generating capacity. Indeed, the debate on the future of BETTA includes substantial argument that a new system able to cope better with variable demand may need, at least in part, to reward installed capacity. Phil Baker and Dr Bridget Woodman at the University of Exeter argue that this means firms must instead attempt to recover some of their investment costs through the BETTA market. However, in an efficient market constraint costs should only be driven by fuel costs—i.e. the relative difference it costs for, say, a coal-fired power station in southern England to generate, versus a similar plant in Scotland. They note that the costs of resolving transmission congestion are observed to be around £90 per MWh, whereas under an efficient market only costs of £10 per MWh should apply.[96] Similar work conducted by the Centre for Sustainable Energy and Distributed Generation demonstrates the same effect.[97] This implies that BETTA potentially overstates the true level of constraint costs and, therefore, the need for additional transmission capacity to meet these constraints may also be overstated.

65.  Ofgem also believes constraint costs have been made artificially high in recent years through the exploitation of market power by certain electricity companies. In April 2008 it launched a formal investigation under the Competition Act 1998 into the behaviour of Scottish Power and Scottish and Southern Energy. The complainants alleged that the companies may have withheld generating capacity from the wholesale forward market while using the same plant to supply balancing power to National Grid at excessive prices.[98] Ofgem closed the investigation in January 2009, stating that to continue would have been an inefficient use of resources given the low likelihood of making an infringement decision under the Act.[99] Nevertheless, the regulator estimates that up to £125 million of the £262 million of constraint costs incurred in 2008/09 could potentially have been the result of the misuse of market power.[100] Because of the difficulties Ofgem believes it faces in applying the Competition Act 1998 legislation to the wholesale electricity market, it has argued in favour of being able to place a Market Power Licence Condition on generators that would strengthen its ability to carry out investigations.[101] The Energy Bill currently before Parliament includes provisions which would give the regulator these powers.

66.  In February 2009 Ofgem wrote to National Grid highlighting concern at the level of constraint costs, and asked it to conduct a review considering possible changes in the way they are recovered. In May the company proposed a modification to the BSUoS charging methodology—referred to as GB ECM-18. This would see constraint costs that arise from the non-compliance of a derogated transmission boundary, such as the Cheviot interconnection, being levied on a locational basis to all exporting generators behind that boundary. Ofgem is now consulting on this proposal and expects to make a decision before the start of the next charging year on 1 April 2010.[102]

67.  If implemented, GB ECM-18 will inevitably shift the burden of BSUoS charges from generators in England and Wales onto those in Scotland. Depending on how generators respond, it will also potentially reduce the level of constraint costs across the system by encouraging less generation north of the border and more in the south. National Grid also believes the reforms would reduce companies' ability to exercise market power when the system is constrained.[103] The proposals met with criticism from some our witnesses. Scottish Renewables told us: "It is conceivable that generators behind a number of boundaries will face significant additional […] charges which may cause the suspension of a number of projects".[104] However, National Grid's analysis suggests that though wind generators in Scotland would pay more, it would be marginal thermal (i.e. fossil fuel-based) plant that would be incentivised to generate less.[105] Scottish Power, which would be most affected by GB ECM-18, also expressed concern stating: "[...] we do not see ourselves as a cause of the balancing costs. We are unable to generate as much as we would like because the network is not strong enough".[106] However, others were in favour of greater locational pricing within the BSUoS charges, noting that the current system, which does not minimise constraint costs, creates incentives for inefficient investment in transmission assets.[107] Prof Strbac also argued that moving towards locational BSUoS charges would facilitate greater sharing of network capacity by, for example, encouraging conventional power stations in Scotland to reduce their output on windy days.[108] He also considered that, in the future, the sharing of network capacity between generators will be a key feature of the smart grid.

68.  It is also worth noting that once the current upgrade of the Cheviot Boundary is complete it is possible that it will then comply with the SQSS and no longer require a derogation. Given the locational charges under GB ECM-18 apply to a derogated boundary, many of the concerns raised by the Scottish generators may prove unfounded in the long run. The debate may also be superseded by new charging arrangements that could arise from DECC's consultation on an enduring access regime for new generators, which we discuss later in this Chapter.

69.  Constraints occur on the transmission network when the system is unable to transmit the power supplied at a particular location to where demand for it is situated. National Grid's management of these constraints gives rise to costs, which are met by generators and consumers. The level of constraint costs are an important signal of investment needs. It is, therefore, vital that this signal is accurate. We are concerned that the nature of the British Electricity Trading and Transmission Arrangements (BETTA) appear to artificially inflate the level of constraint costs. We note the general review of the BETTA market announced by the Government in the Pre-Budget Report in December 2009. However, we recommend Ofgem conducts a specific review of the BETTA market with a view to addressing this issue. We also support the Government's intention to enhance Ofgem's powers to regulate against companies artificially inflating constraint costs.

70.  Whilst we agree in principle with the current proposals to implement locational pricing for the Balancing Services Use of System charges as a means of reducing constraint costs in the short run, we question whether Ofgem should continue to pursue the modification brought forward by National Grid, given it could be replaced by another set of charging arrangements in the short to medium term when DECC implements a new regime for determining transmission access.


71.  The amount transmission companies can spend on operating and maintaining the system, as well as investment in new network capacity, is set through five-yearly price control reviews. These costs are recovered from both generators and suppliers through Transmission Network Use of System (TNUoS) charges. In 2009/10 the amount collected through these charges will be over £1.4 billion, representing around 3-4% of electricity customers' bills.[109] From April 2009, the TNUoS generation tariff has comprised four separate elements. Three of these vary according to the location of the generator on the system, the largest component of which is the 'wider' locational charge, which varies from £21.59 per kW in North Scotland to a negative charge of £6.68 per kW in the Cornish Peninsula. These locational charges will net around £85 million of revenue in 2009/10. The remaining component of the TNUoS generation tariff is a residual charge, which is non-locationally specific, and is paid at a flat rate. This raises a further £300 million. Generators pay 27% of total transmission costs with the rest met directly by consumers through electricity suppliers—around £1,041 million in 2009/10.

72.  The locational element of the TNUoS charges was the source of considerable debate in the course of our inquiry. The tariff is in place because National Grid's licence obligations require it to charge its customers cost-reflectively.[110] Higher costs in the north are meant to reflect the greater cost of transporting electricity across longer distances to centres of demand in the south, where network capacity is also greater. In so doing, the TNUoS charges are designed to provide an economic signal to generators and developers to work within existing network capabilities and locate nearer to the source of demand. This then reduces the need for investment in new network capacity, which can be expensive and time-consuming to deliver as has been the experience to date, for example, with the Beauly-Denny Line. It also has potential environmental benefits, both in decreasing the transmission losses arising from the transport of electricity over long distances, and in reducing the need for new pylons that can blight the landscape.[111]

73.  Both Ofgem and the Government argued strongly in favour of cost-reflective transmission charges. The regulator believes it promotes efficient development and use of the network, which is in the interests of current and future consumers.[112] The Minister told us: "If we do not have a signal that helps people think […] about how and where they will locate their plant, then there is a risk obviously that we get too much investment in areas across the system that are too far from demand".[113] In their evidence to us, organisations including the Association of Electricity Producers, the Institution of Engineering and Technology, the Renewable Energy Association and E.ON UK, among others, also supported the principle of locational pricing.[114]

74.  Generators in Scotland have, by contrast, been highly critical of the locational element of the TNUoS generation tariff, arguing that it creates an uncertain environment for investment and discriminates against renewable generation. Scottish Renewables argued that some forms of renewable energy, such as wind, are not able to respond to the locational price signal in the same way that gas-fired power stations can. The trade union Prospect told us that locational pricing is "a legitimate mechanism for encouraging construction of fossil fuel fired or nuclear generation near the load centres, but acts as an additional disincentive to remote renewable generation".[115] Scottish Renewables argued this results in income derived through the Renewables Obligation in Scotland effectively being transferred to conventional generators in the south.[116] Scottish and Southern Energy too were critical of the level of locational tariffs, noting that the current approach had created charges that were "volatile and unpredictable".[117] The company told us this acted as a deterrent to investment by generators and that this uncertainty also undermined the signals for investment in additional transmission capacity.[118]

75.  With the support of the Scottish generators, in 2008 the Scottish Executive brought forward a proposed modification to National Grid's transmission charging methodology, known as GB ECM-17. This proposed an alternative model based on a 'postage stamp' approach to charging where a GB-wide tariff is levied for each unit of energy exported onto the network. Scottish Renewables argued this would create a regime that was "proportionate, predictable and stable and will do much to promote new generation in the UK".[119] It would also reduce transmission charges for generators in Scotland. Socialising the cost of transmission across all generators, irrespective of location, is also the approach used in countries such as Germany.[120] National Grid consulted on the proposal in 2009. It found that cost reflective charging was still consistent with the Government's objectives for increasing renewable generation and reducing carbon dioxide emissions, and that the existing approach did produce tariffs that were stable and predictable for the vast majority of sites. The company, therefore, rejected the modification.[121]

76.  Ofgem was highly critical of 'postal charging' for transmission access.[122] The regulator argued such an approach would discriminate unduly against generators in the south who impose lower costs on the system, whilst also creating incentives for over-investment in transmission capacity in the north. It also noted the mirroring of charging methodology for gas transmission, where gas users in Scotland benefit from lower charges than those further south because they are closer to the major entry points to the gas transmission system. Ofgem told us it would be difficult to justify changing the charging approach for electricity without doing likewise for gas.

77.  Some witnesses suggested that the level of transmission charging did not target costs to location enough. Prof Strbac told us the revenue derived from the locational element of the TNUoS charge was small relative to the revenue from the residual charge, which is spread across all generators—£85 million as opposed to £300 million.[123] This in turn is dwarfed by the £1,041 million of transmission charges paid by consumers. Dr Michael Pollitt noted too that the potential growth of offshore wind meant generators had many more options of where to locate new renewable capacity and, therefore, respond to locational signals.[124] The Renewable Energy Association also told us that whilst Scotland is an extremely important resource for renewable energy, "it is not, however, the only show in town".[125]

78.  The Department and Ofgem argued that locational charges were not harming the development of renewable generation in Scotland. DECC stressed that the nature and level of the TNUoS charge and other related transmission-related costs were taken into consideration when determining the level of subsidy available through the Renewables Obligation.[126] The regulator's Chief Executive told us proposed onshore wind projects as far north as Orkney typically had estimated rates of return on investment of up to 40%, in contrast to around 12% for a gas-fired power station.[127] Moreover, access to finance in the current economic climate, gaining planning consent, and securing a grid connection are all seen as more important determinants of investment in new renewable generation.[128]

79.  However, the treatment of wind generation specifically within the charging regime was raised as a concern.[129] At present, generators are charged according to their peak load condition—i.e. the output they contribute to meeting peak demand. Yet wind generation is variable in nature, having a low load factor of around 30%, and so makes a low contribution to peak demand. This is not, though, reflected in the network charges—if it were wind generators would pay significantly less.[130] National Grid acknowledged this concern in its Conclusions Report on GB ECM-17.[131] Whilst this may not be a significant factor in determining the investment case for new wind generation at present, it could become more so as financing conditions ease, and reform of the planning system and grid access regime are implemented. We discuss the latter of these in the next section.

80.  We are concerned that the current system appears to charge wind generators disproportionately more than conventional generators for grid usage. We believe that it is imperative that transmission charges should not discriminate against renewable energy wherever it is located in Britain. Whilst we received conflicting evidence on this matter and acknowledge that other factors such as the planning system, grid access and financing play an important role in determining the investment case for new renewable generation, we believe it is vital that this issue be fully investigated as soon as possible. We note Ofgem's long-term commitment to the model of locational charging, but given the evidence we have received we recommend the Department establishes an independent review to develop an appropriate transmission charging methodology.

Grid access

81.  Access to the network is vital for electricity producers as without it they cannot deliver their product to consumers, nor do they have confidence to invest in new generating capacity. The issue also ties closely with the case for investment in new transmission assets and the network charging regime. In this section we look at the problems new generators face in acquiring network connections and the Government's response to these concerns.


82.  Under the existing transmission access arrangements the grid operator follows an 'invest and connect' approach for new projects whereby they are only connected if there is sufficient grid capacity to accommodate their maximum potential output without causing a restriction on the production of existing generators.[132] The speed with which a generator can gain access will depend on the amount of grid reinforcement needed; the ease with which planning consent can be acquired for any work; and the amount of generating capacity applying to connect in each part of the network.[133] Unless there is already spare capacity on the grid, generators must wait until the operator has made the requisite reinforcements before they can connect. Those applying for access are treated on a first-come-first-served basis, which means projects that are less viable can block those that are further ahead or could be advanced earlier. Indeed, the position is rather similar to people booking rooms in hotels before they have found out whether they can get the time off work.

83.  These arrangements have resulted in a queue of projects at various stages of development waiting for connection with a combined capacity estimated at between 60 GW and 80 GW—equivalent to all Britain's existing generating capacity.[134] Around 17 GW of this is renewable generation, with some projects holding a connection date as late as 2023. At present half of the queue will have to wait at least five years for grid access.[135] In Scotland 9 GW of renewables is waiting for connection, a large proportion of which has connection dates later than 2018.[136] Many projects with connection offers do not come to fruition. However, even with an attrition rate of 50% assumed by several of our witnesses, the backlog of schemes is long. For projects in Scotland the queue is primarily the result of the delayed upgrading of the Beauly-Denny line and the Cheviot Boundary. Scottish Renewables estimate that once the former of these is in place more than 5 GW of renewables in Scotland will be able to connect to the system.[137] Scottish Renewables told us: "If you apply a planning attrition rate of 50% to the 9 GW [...] then these reinforcements will be sufficient to provide the necessary firm access".[138]

84.  It is clear that the existing regime creates considerable uncertainty for both renewable and conventional generators and restricts access to the energy market. As one independent generator said: "This makes continued investment in the UK very difficult in comparison with some other jurisdictions".[139] Scottish and Southern Energy told us: "[...] it is not surprising that potential investors (particularly in emerging renewable technologies) are opting to locate elsewhere in the global energy market".[140] The Government and the regulator have recognised the need for change.[141] Accordingly in 2008 they launched the Transmission Access Review (TAR), the aim of which was to provide a programme of reform that would significantly reduce grid access barriers. The TAR process is still underway. It was meant to deliver both short-term measures to reduce the current queue, as well as an enduring access regime for the long term. We consider each of these in the next two sections.


85.  In the debate over improving grid access one approach has come to the fore, at least as a short-term solution—the concept of 'connect and manage'. This can take a variety of forms, though the common basis is that all generators who wish to connect to the grid are allowed access irrespective of whether any necessary transmission reinforcements have been completed.[142] In so doing both existing and new generators have firm access rights. The system operator manages any resulting congestion on the network on a day-by-day basis by taking offline generating capacity where there are pinch-points, for which the owners are compensated—these give rise to the constraint costs discussed earlier in this chapter. This is the approach currently used in Germany and Denmark.[143]

86.  In May 2008 Ofgem announced that it had approved National Grid's proposal to introduce changes to the rules on connections known as 'interim connect and manage'. This will enable both renewable and conventional generators to link to the grid as soon as their local connections are ready, rather than wait until any wider system reinforcements have been completed. The regulator expects the measures to be in place only in the short term in anticipation of their replacement with an enduring access regime in the near future. Initially, the combination of this and more proactive queue management by National Grid allowed around 450 MW of renewable projects to gain earlier connection dates in Scotland.[144] National Grid has now identified a further 450 MW of renewable projects that can connect earlier than expected. This constitutes about a fifth of the current queued capacity in Scotland that could be delivered in the next decade (again, assuming a 50% attrition rate).[145]

87.  Overall, the industry has welcomed the introduction of the interim measures.[146] There has, however, been some concern over the level of constraint costs that will arise from their implementation.[147] Where other countries have introduced 'connect and manage' it has led to a significant increase in network congestion and associated constraint costs.[148] The extent of these will be determined by the time it takes for planned investment in new capacity to take place and, before then, by how the costs are distributed across network users. We have discussed already in this Chapter National Grid's proposal to make the Balancing Services Use of System (BSUoS) charges locationally determined, rather than socialised across all generators. The level of anticipated constraint costs arising from the 900 MW of additional renewables capacity, and hence the impact locational pricing might have, has been a matter of disagreement between the industry and the regulator.[149] Moreover, National Grid believe locational pricing within the BSUoS will have a greater effect on conventional capacity in Scotland than on renewables. However, debate over these issues is likely to be superseded by the introduction of a long-term access regime.


88.  The arrangements by which generators gain access to the network are set out in the Connection and Use of System Code (CUSC). This is a modifiable document such that Ofgem can change any part of the access regime. However, it can only do so with amendments proposed to it by the industry—the regulator cannot change the CUSC of its own accord. This meant it was the industry's responsibility to lead on developing an enduring access regime. As an incentive the Government included in the Energy Act 2008 a provision for the Secretary of State to impose a regime if the industry failed to develop a satisfactory solution.

89.  National Grid began the process by proposing in April 2008 a suite of amendments to the CUSC which over the course of 2008 and 2009 were discussed and developed by industry working groups. The regulator's role was to monitor and report on progress to the Department. In early 2009 it became apparent to Ofgem that the emerging proposals for enduring reform would lead to significantly higher network charges for low-carbon generation, particularly renewables, than for conventional generators. In evidence to us in May the regulator's Chief Executive referred to analysis by National Grid suggesting that one of the proposed approaches would give rise to charges of £70 per kW for a wind farm in Scotland versus £10 per kW for a generator in England and Wales. He described this kind of outcome as "absurd".[150] Frustrated by what it saw as the industry's unwillingness to engage in other options, in June 2009 the regulator wrote to the Secretary of State recommending he use his powers under the Energy Act 2008 to take action into his own hands. In his letter the Chairman of Ofgem, Lord Mogg, wrote: "The electricity generation sector must clearly play a major role in delivering the UK's ambitious emission reduction targets and it is regrettable that the industry appears to have fallen at the first hurdle".[151]

90.  Accordingly, in August 2009 the Department published a consultation setting out three possible variations of the 'connect and manage' model, summarised below:

  • Socialised—A model that fully socialises any additional constraint costs. Under these arrangements costs would be shared between all users of the network and ultimately borne by consumers;
  • Hybrid—This targets some, but not all, of the additional constraint costs on new entrant power stations; and
  • Shared cost and commitment—This offers the choice to new and existing power stations to commit to fixed network access in return for greater certainty over charges, or to opt out and be exposed to additional constraint costs.[152]

91.  The Department's consultation came after the Committee had completed its evidence-gathering. We note, though, Ofgem's recent response to the consultation.[153] This expressed concern that all three of the approaches would create significant additional constraint costs in the range of £2.9 billion to £3.5 billion between 2009 and 2020 (on a net present value basis), which it states would ultimately be borne by consumers. It argues too that until additional grid capacity is in place these regimes would create opportunities for generators to exploit market power and increase constraint costs further. Furthermore, the regulator criticises the Department for failing to take a holistic approach in its proposed reforms. For example, they fail to address wider issues concerning the current arrangements, including the nature of access rights; the way in which generators commit to use the system and the costs of doing so; and the compensation they receive when constrained off the network.

92.  There are a variety of ways in which the Department could define a long-term grid access regime. For it to be successful, however, the evidence we received suggests it should contain four key features. First is the principle of generators sharing access to the network. While the development of the smart grid will reduce the need for investment in generating capacity significantly over a continuation of the current approach of building supply to always meet peak demand, it is still the case that total generating capacity in the future is likely to be higher than it is now for a given level of demand, primarily because of the intermittency of wind generation. DECC's memorandum suggests Britain's total capacity could be around 105 GW in 2020 for current levels of demand, compared to 80 GW today.[154] Consequently, the Department believes there is an opportunity to share network access more efficiently. In so doing this reduces the need for new investment in transmission capacity.

93.  Sharing access represents a move away from the current approach whereby all generators have guaranteed entry rights to the grid and are compensated when they are constrained off the system. Instead it means a system where generators potentially choose the extent of their access rights, and pay accordingly through their transmission charges. For example, there are already situations where wind farm generators have agreed contractual arrangements with conventional power stations to share grid entry capacity, with the latter providing back-up for the former when the wind does not blow.[155] The concept of sharing access was also a key part of the original amendments to the CUSC put forward by National Grid in 2008 in developing an enduring access regime.

94.  Sharing network capacity has met with considerable opposition because it would entail the removal of existing transmission rights from incumbent generators.[156] The Association of Electricity Producers (AEP) argued that generators would have made investments on the basis of having secure transmission access rights for the lifetime of a power station's operation, and that this was what they paid Transmission Network Use of System (TNUoS) charges for.[157] In evidence, the AEP quoted a Chief Executive from the industry who had said: "I simply cannot sign off the building of a brand new power station to come into use occasionally to deal with the variable supply of energy from renewables".[158] Ofgem, in turn, have questioned the companies' assertion that their access rights are guaranteed in perpetuity.[159] Generators are liable only for one year's TNUoS charges at any given time, and are free to reduce the amount of access they require with only five days' notice to National Grid leaving consumers to cover the cost of any assets stranded.[160] The regulator concludes: "This lack of user commitment undermines the efficiency of network investment, and will delay the connection of new generation".[161] Disagreement over this issue contributed to Ofgem's decision to recommend the Secretary of State to intervene in the process.

95.  One reason why generators are unwilling to surrender their guaranteed grid entry is because the regulatory framework distorts the relative cost of firm versus finite access rights. With firm access, companies have the security of knowing they will receive compensation if they are constrained off the system, whereas non-firm access is comparatively expensive because power stations do not know whether they will be able to export to the grid. Under the existing regime there is little incentive for generators to relinquish access capacity, even if they do not make full use of it at all times. The key to solving the impasse, as one witness noted, is to ensure that both options have efficient costs attached to them so that generators' decisions on the level of grid access they require reflects the costs they will incur to the system.[162] This may need to be combined with some kind of incentive mechanism within the market that ensures a degree of spare generating capacity, such as existed under the previous electricity trading arrangements, known as the 'Pool'. This is because, at present, generators rely on the receipt of constraint payments—which would be significantly reduced if they did not have firm access to the network—to cover some of their investment costs.

96.  The second key feature of an enduring regime, which is linked to the issue of access sharing, is the priority of low-carbon technologies over conventional generation. The Association of Electricity Producers argued that all forms of generation technology should compete on a level playing field and network connection, access and charging arrangements should be non-discriminatory, cost-reflective and transparent.[163] This would be more persuasive if the Government did not have a clear strategic objective to decarbonise the electricity system. Phil Baker and Dr Bridget Woodman at the University of Exeter told us the replacement role of renewable generation suggests that it should: "[…] be endowed with a natural priority in terms of energy dispatch and also in accessing the electricity system, thereby ensuring the maximum contribution to decarbonisation".[164]

97.  The third key feature is the greater role of demand in the access regime. We saw earlier in this Chapter that the bulk of TNUoS charges are paid directly by consumers. This imbalance in the apportionment of costs means a one megawatt reduction in demand is treated differently by the charging regime to a one megawatt increase in generation, despite the impact of both actions on the system being the same.[165] Furthermore the current DECC proposals for an enduring regime exclude the demand-side from playing a greater role in the access regime to alleviate constraints when they arise. We have seen already that the greater role of active demand-side management will be a vital part of a future smart grid.

98.  Finally, several witnesses stated that an enduring access regime, whatever form it takes, has to provide long-term regulatory certainty to all market participants for them to have the confidence to make investments. Scottish and Southern Energy told us: "Stability and certainty in the grid access and charging arrangements are essential to achieving the EU 2020 target".[166] E.ON UK also said: "Long-term regulatory certainty […] is essential to give confidence to and ensure investment in the network and generation with longer lead times, such as nuclear".[167] Achieving this outcome would have to be balanced with the need to develop a regime that also facilitated access sharing.

99.  The old arrangements for gaining access to the transmission network gave rise to a queue of at least 60 GW of projects at various stages of development, a large proportion of which are renewables, some of which have potential connection dates as late as 2023. A new regime is vital if the Government is to meet its targets for renewable energy and emissions reductions. We welcome the 'interim connect and manage' arrangements, which should facilitate the earlier connection of 900 MW of renewable capacity in Scotland. We are, however, concerned by the lack of progress in developing a long-term access regime. It is extremely disappointing the industry has not been able to agree reforms and the Government has had to intervene. As far as possible, it is important an enduring regime is based on consensus between all parties—the Government, the regulator and the industry.

100.  We believe that to facilitate cost-effectively the formation of a smart grid and the delivery of the Government's strategic objectives, a long-term regime must contain four key features:

  • Greater sharing of network access, particularly between renewable and conventional generators. This will reduce the need for investment in grid capacity, and the likelihood of large constraint costs, although it may need to be supported by additional market arrangements that guarantee spare generating capacity on the system;
  • Prioritisation of renewables in electricity dispatch to maximise their contribution to decarbonising the energy system;
  • An equal role for the demand-side in managing network access; and
  • Arrangements that provide a degree of stability and regulatory certainty for generators to have the confidence to make investments.

We urge the Department to move quickly to ensure an enduring regime is in place as early as possible in 2010.

The industry's rule-making process

101.  In November 2007 Ofgem announced its intention to conduct a review of the various arrangements for governing the industry's code and charging methodologies. The regulator believes the existing governance procedures are not effective at bringing about the coordinated and timely reform needed to deliver the Government's climate change and security of supply objectives—a view borne out by its recent experience in attempting to implement an enduring transmission access regime.[168]

102.  The Codes Governance Review, as it is known, has a number of work streams on which Ofgem is currently consulting. One set of proposals covering Major Policy Reviews would give the regulator power to require network licence holders to implement code modifications consistent with the conclusions of any such reviews.[169] Although changes would be subject to thorough consultation, this would see a major reallocation of rule-making power away from the industry to the regulator. The Chief Executive of Ofgem told us: "[…] what we have to be able to stop going forward is the vested interests within the sector, either filibustering or just straight blocking reform […] we want as an organisation to be able to initiate change".[170] As a quid pro quo Ofgem has proposed that where code modifications are likely to have only minimal impact on consumers or competition the industry would be allowed to self-govern, rather than requiring authority from the regulator. In a separate consultation, Ofgem has also proposed opening up the procedures for modifying network charges. At present, these are determined by the network owners—network users, interested parties and consumers are not able to influence how use-of-system or connection charges are determined. The regulator's proposals seek to address this disparity. In both cases, Ofgem expects to implement its reforms in 2010. It notes that any changes to the governance procedures will not inhibit network companies from seeking judicial review or a Competition Commission referral with respect to any future changes to the industry codes or charging methodologies by the regulator, which they see as unreasonable.

103.  We welcome Ofgem's decision to review the industry's rule-making process. The existing system, under which only network owners can propose changes to the grid codes and charging methodologies, has for far too long forestalled reform in areas such as transmission access. The regulator's proposal that it take powers to implement code amendments arising from major policy reviews, whilst conceding power in areas of less significance to consumers or competition, is a sensible approach. So too is the proposal to make governance of the charging methodologies more inclusive. Changes in both these areas will facilitate the delivery of the Government's climate change and security of supply objectives.

Developing offshore transmission

104.  Britain has some of the best wind resources in the world. It is for this reason the Government expects wind power to be the main contributor in meeting our share of the EU 2020 target for renewable energy. A large proportion of this will be built offshore, primarily in the North Sea, but also in the Irish Sea.

105.  Offshore wind development in British waters began in 2000 with the Crown Estate's first round of leases for 13 locations. The first project under Round 1, North Hoyle, came into operation in December 2003, and a number of projects have followed since. In 2002 and 2003 the Crown Estate ran a second licensing round, awarding 10 companies the rights to develop a total of 15 sites in three strategic offshore areas. The estimated potential generating capacity arising from Round 2 was between 5.4 and 7.2 GW.[171] At present, nine offshore wind farms are operational with a combined capacity of 688 MW. Another five schemes with a capacity of 1.1 GW are under construction.[172] In January 2010 the Crown Estate announced the results of its third licensing round, awarding contracts for development in nine zones, which are much further out to sea, that could lead to 32 GW of offshore generation.[173] In this section we look at the difficulties faced in connecting offshore wind farms to the onshore network, and the Government and Ofgem's framework for ensuring timely investment in offshore transmission.


106.  Delivery of the scale of generating capacity anticipated in Round 3 will require substantial investment in offshore networks. The Department estimates that investment worth up to £15 billion is necessary over the next decade to connect all three rounds of sites licensed so far.[174] This equates to more than twice the asset value of the existing onshore network. In addition, the large flows of electricity expected from offshore wind farms will necessitate reinforcement in particular parts of the onshore network. These investment needs formed part of the Electricity Networks Strategy Group's (ENSG) recent analysis discussed earlier in this Chapter.[175] These works will need to progress in good time as the level of offshore generating capacity connecting to the mainland grows.

107.  Building networks offshore poses significant technical and regulatory challenges. The construction of large electrical power infrastructure in difficult offshore environments, particularly for the Round 3 projects, has not been attempted anywhere else on the same scale. The Institution of Engineering and Technology (IET) told us: "the installation of rather sophisticated electronic and other equipment offshore is new and […] something that will be pioneered in UK waters".[176] Offshore transmission will use high-voltage direct current (HVDC) as opposed to alternating current (AC) onshore because for undersea cables it is cheaper and has lower losses. There will also be operation and maintenance risks once the infrastructure is in place. The harsh North Sea environment will mean turbines and network connections are not always accessible. This will require much higher levels of system reliability than onshore. The IET argued the regulatory framework needs to recognise these risks.[177]

108.  To manage electricity flows from offshore the Department has extended National Grid's GB system operator role. Accordingly, the company and the regulator have been working to modify the various grid codes to take account of offshore transmission, which is defined as 132 kV or above—the same as in Scotland—as opposed to 275 kV or above onshore in England and Wales. Some of our witnesses raised concern at the potential inequitable treatment of offshore wind within the regulatory framework. Centrica highlighted that offshore generators would not pay Transmission Network Use of System (TNUoS) charges in the same way as onshore generators, where the majority of costs are currently socialised across all generators and consumers. Instead, the company notes that substation and cable costs will be targeted directly at the offshore generator, thus, it says, increasing their network costs by a factor of ten or more.[178]

109.  Prof Strbac pointed to further discrimination in the regulations concerning the compensation generators receive when the network is unavailable for them to input electricity. Whereas onshore power stations are entitled to such compensation, provided they comply with the network standards, this is not available to similarly compliant offshore wind farms.[179] On the grounds that both onshore and offshore network security standards are based on the same principles, Prof Strbac saw no justification for this differential treatment and thought it could undermine seriously the financial viability of any offshore generators that did experience difficulties with their transmission connections.[180] In response National Grid argued that offshore wind farms would have to meet lower connection and security standards than their onshore counterparts and, therefore, could not expect the same level of compensation.[181]

110.  A further challenge for offshore networks is in ensuring the supply chain is able to deliver the equipment on time to connect new wind farms. The British Wind Energy Association (BWEA) estimates that approximately 7,500 km of HVDC cable will be required by 2020 to link up all the offshore projects planned. Yet current global production of this cable is only around 1,000 km per year.[182] There will also be demand for cabling as part of other countries' offshore programmes, for example, Germany. The industry, therefore, believes there is a major export opportunity for Britain developing domestic cabling production. BWEA told us: "If the right signals are sent to the cable companies, the resulting factories could be sited in the UK, with benefits in terms of jobs and exports".[183] The licensing regime will be a key determinant of the UK's attractiveness as a place to invest.[184] We discuss this in the next section.

111.  There are many challenges associated with the expansion of the electricity network offshore. It is important the regulatory framework reflects these difficulties and treats generators connecting offshore equitably vis-à-vis their onshore counterparts. The offshore wind industry presents a significant commercial opportunity for British industry, which requires a regulatory regime that will stimulate domestic investment in cabling and associated equipment manufacture.


112.  The Department and the regulator have been working together to develop the licensing regime for the developing offshore transmission network. In the same way as for the onshore network, licensed companies will be responsible for building, owning and maintaining the offshore cables. However, rather than the area-based monopolies currently enjoyed by the existing three companies, licences will be awarded by tender as new offshore generators seek connection. Offshore transmission owners (OFTOs) will receive a 20-year regulated income stream from Ofgem and generators will pay to use the cables through annual transmission charges. These costs, along with those associated with the stranded assets of any failed projects, will ultimately be borne by consumers.[185]

113.  The first round of competitive tenders began in summer 2009. In December Ofgem announced a shortlist of six companies or consortia bidding for nine projects.[186] The total value of the work is more than £1 billion and will connect 2 GW of offshore wind capacity. The regulator expects to announce the winning bids in May 2010. The first tenders to appoint OFTOs will entail taking over the ownership and maintenance of cables that are already under construction from developers. Ofgem refers to these as transitional arrangements. In the future, OFTOs will be appointed to design and build the grid connections themselves, as well as own and maintain them. The regulator is currently consulting on the enduring regulatory framework that will govern these activities.[187]

114.  Britain is not the first to use an auctioning approach for new transmission wires—Argentina and Chile have done so previously and successfully.[188] However, it is the first to use auctioning for offshore connections. Both the Department and Ofgem argued that there are various advantages to their approach. First, they are keen to increase the number of parties able to build the offshore connections and deliver them quickly so as to minimise the risk of delaying new wind farms coming on-stream.[189] Second, they believe the auctions will create cost savings for consumers, which the regulator predicts could total around £1 billion from all three offshore rounds. Third, the 20-year income streams for OFTOs will, the Department argues, require less regulatory oversight than the current five-yearly price control reviews.[190] Finally, Ofgem hopes the competitive approach will also encourage greater innovation.

115.  Several of our witnesses supported the new framework for licensing OFTOs.[191] The Association of Electricity Producers told us: "the competitive arrangements […] will deliver benefits in terms of lower costs, more innovation, and getting more companies in to finance these networks".[192] Another witness noted that Britain will benefit from being one of the first countries to adopt this approach, and will therefore attract European and American companies that have not previously been involved in the British market.[193] This appears to have been borne out in the current auction where only one of the six shortlisted bidders is an incumbent transmission company—National Grid.

116.  However, a number of witnesses also voiced concern over the new licensing regime. The Energy Networks Association highlighted the complexity of the arrangements, which ARUP argued could undermine some of the expected benefits.[194] Another risk is that the rules may prevent the exploitation of synergies between different network concessions in the operation of offshore generation and transmission assets.[195] Also, the tendering for individual projects potentially reduces the incentive for companies to invest in their capability to deliver offshore connections because they will face uncertainty over whether they will win future work.[196] Moreover, with limited experience of the costs and risks of these investments, combined with potential supply chain constraints, companies may underestimate such factors and fail to deliver on their bids.[197]


117.  The Department told us the majority of Round 1 and 2 projects will connect 'point to point'.[198] This means each offshore wind farm will have its own transmission cables that connect with the onshore network. Later Round 3 schemes, though, are likely to follow a more zone-based approach whereby a group of wind farms in a particular area, whether coming on-stream simultaneously or phased over time, use a single link to connect onshore. The Department believes this will ensure the development of the offshore grid in a co-ordinated way.

118.  Many of our witnesses argued the Government and Ofgem's licensing framework failed to take a long-term strategic view of the development of the offshore network.[199] A particular concern was that 'point to point' connections would result in the construction of radial transmission lines dedicated to individual wind farms, leaving little scope for the later development of an integrated offshore network that may connect together a number of different projects in the future. Many believe this will result in the construction of connections in a piecemeal fashion and the evolution of a sub-optimal offshore network that is more costly and less efficient. The Association of Electricity Producers (AEP), for example, argued that the Government instead needed to adopt a more holistic approach, ensuring the development of connections for the first offshore wind farms was in line with what would be required in the future when the much larger Round 3 schemes start to come on-stream—investment ahead of need in the same way that Ofgem is implementing for the onshore network.[200] Scottish Renewables argued too that such an approach would facilitate the greater interconnection of the British and European electricity networks.[201] As one witness said: "A strategic and coordinated approach to offshore subsea networks which link offshore renewables and also interconnect with Europe will deliver a better solution in the long term".[202] One approach suggested by the British Wind Energy Association (BWEA) was for the appointment of a single OFTO for each of the Round 3 zones. They would be responsible for connecting a number of schemes in the same geographical area. This, BWEA argues, would allow them to adopt a more coordinated approach, investing in a transmission link to the onshore network early on that provided efficient connection for later projects.[203]

119.  In response to these criticisms Ofgem told us the primary advantage of using 'point to point' links was that they helped ensure the timely connection of new offshore wind farms, which might otherwise be delayed if it adopted a more strategic approach.[204] It noted too that OFTOs' licences would include headroom of up to 20%, allowing them to extend further their cable or develop a small network within clusters of wind farms.[205] Elsewhere, the Minister argued 'point to point' connections were more cost-effective.[206] The construction of even simple offshore infrastructure is expensive and involves technical challenges. As one witness said, there is "a simple technical and economic argument that tells you to [use] 'point to point' for these sorts of amounts", referring to the size of the current Round 1 and 2 schemes.[207] Finally, the Chief Executive of the regulator also noted that the asset bases of the transmission companies impacts upon their stock market value. As such it was unsurprising they would oppose the auctioning of offshore transmission licences whilst advocating investment in network assets ahead of need.[208]

120.  Connecting the first three rounds of licences for offshore wind farms will require a capital investment of £15 billion—twice the value of the existing onshore transmission network. We therefore note the auctioning approach for the delivery of future offshore transmission links to ensure costs are minimised for the consumer. In the short to medium term this will lead to the direct 'point-to-point' connection of Round 1 and 2 wind farms as the most cost-effective and technically feasible way forward, which also militates against the possibility of delays. However, risks remain, particularly if companies underestimate the cost of the work for which they have tendered. This means the Department and Ofgem must keep its approach under review. Moreover, it is not yet clear how the present framework will deliver the most efficient network solution to connect the 33 GW of offshore wind that is possible under Round 3. There remains a risk that the current approach could lead to the piecemeal development of the offshore network that is less cost-effective in the long run. We note that the Department merely believes that zone-based approaches to connecting wind farms onshore will develop. We do not consider this is a sufficiently robust approach, and recommend the regulator conducts more analysis to develop a route-map of how it expects the competitive tendering regime to evolve to meet this long-term challenge.


121.  The anticipated expansion of wind generation in Britain has led to greater discussion of the potential role of interconnection in the energy system. This is the trading of electricity between countries through grid connections known as interconnectors. At present the GB system has two such links—one with France and another with Northern Ireland. Under European law, interconnectors may be funded as regulated assets, which means consumers are exposed to the risks of their costs exceeding the benefits. However, under certain conditions a merchant approach is permitted that allows investor-led companies to build interconnectors themselves.[209] At present a number of projects are in development under the latter method. A link with the Netherlands is under construction and projects are at an advanced stage of planning for new links with Belgium, Ireland and France. Proponents argue there are two main benefits to greater interconnection—improved security of supply and greater competition. In this section we consider each of these in turn, as well as alternatives to interconnection. We then assess the potential of the next generation of interconnection in the form of a European 'super-grid'.


122.  One of the main advantages of linking the GB electricity grid to other markets is that interconnectors can provide balancing services when there is either a shortage or a surplus on the system. In so doing they can help ensure security of supply. Most of our witnesses acknowledged the importance of this role.[210] Interconnection will also have a part to play in managing the impacts of intermittency as the level of wind generation in Britain increases.[211] Work conducted by the Centre for Sustainable Energy and Distributed Generation (SEDG) suggests that wind curtailments on the GB system may become material when the level of wind penetration exceeds 20%. This would be particularly prominent when low demand conditions coincide with high wind outputs.[212] Excess supply could also lead to within-day collapses in electricity prices, and even negative prices.[213] Such price volatility would undermine the investment case for new generation capacity.[214] However, many believe greater interconnection would allow wind farms to maintain output, exporting surplus electricity to neighbouring countries. In turn, during spells of low generation, the system operator would potentially draw from reserve capacity in other countries. Overall, this would reduce the need for domestic reserve capacity and help ensure generating assets are used more efficiently, thus reducing costs for consumers.[215]

123.  Denmark, which has a high penetration of wind generation, already uses this approach—interconnections with Germany, Norway and Sweden allow it to export excess wind power during periods of low demand and, at other times, draw on the Nordic countries' vast hydroelectric resources. However, Denmark's size in relation to its neighbours enables the management of output fluctuations fairly easily. The balancing services the GB system may require, if over a quarter of the electricity mix was wind, would be an order of magnitude greater. This suggests it would be difficult to manage wind intermittency even if there were a number of interconnections. Moreover, as one witness noted: "weather fronts are, in fact, bigger than countries".[216] It is likely that when wind generation is high on the GB system, the same will be true in neighbouring countries. This would reduce the system operator's ability to export excess supply.[217]

124.  Some witnesses questioned too the overall value of interconnection as a means of securing electricity supplies. Dr Michael Pollitt told us there is tentative evidence that greater links between power control areas actually increases the risk of multinational blackouts.[218] This may be attributed to the additional complexity of system operation over different jurisdictions, and the greater vulnerability of an interconnected network to disturbances arising in other countries.[219]


125.  Another potential outcome of more closely linking the GB system with other countries is that consumers may profit from greater competition in electricity supply.[220] However, several of our witnesses were sceptical of any such benefits, not least because four of the 'Big 6' energy suppliers in Britain are already European companies. The Chemical Industries Association noted: "The UK is effectively on the end of the European network and there is a risk of gaming where pan-European suppliers can make more profit by ensuring shortage of supplies to the UK".[221] Ofgem too argued there is "the potential for exposure to less competitive and less transparent markets".[222] It pointed to current and past experience in Britain's interaction with the European gas network, where there is a greater level of interconnection. There the relative lack of liberalisation on the Continent has arguably led to the British gas market acting as 'lender of last resort' to the European system.[223] Nor has interconnection for gas prevented large price spikes during times of short supply. Dr Michael Pollitt told us that, given the interaction of the gas and electricity markets in Britain, improving the competitiveness of the European gas market might prove a more cost-effective pursuit than trading electricity.[224]


126.  Although interconnection has a role to play in managing wind intermittency there are also other solutions. In Chapter 2 we examined how greater flexibility and integration of demand through smart grid technologies will be crucial in providing balancing services across the network. Smart metering could also facilitate greater fuel substitution where excess electricity could be channelled into domestic water and space heating thermal storage that would otherwise use gas.[225] Denmark has recently begun to adopt a similar approach, preferring to make use of its excess renewable generation to provide heating rather than exporting it at very low prices. Prof Goran Strbac told us the future energy storage capacity of the heating and transport sectors, through the integration of demand and generation, has a much greater potential to provide balancing services than further interconnection.[226]

127.  As the level of wind generation in the electricity mix increases over the next decade, its intermittency and unpredictability will make it increasingly difficult for the system operator to balance supply and demand. A potential solution may be greater interconnection with European networks. However, the lack of progress in liberalising the European energy sector, means Britain risks tying itself closer to markets that lack competition and transparency, as has already happened, many would argue to its detriment, in the gas sector. The Government should continue its efforts to ensure the European Union makes rapid progress on implementing full transparency of Member States' energy sectors so that the UK is not further disadvantaged. In addition, it is not yet clear to what extent the GB system would be able to rely on other countries to provide balancing services, given weather systems rarely conform to national boundaries. The regulator should, therefore, proceed with caution in licensing future interconnection. Moreover, the electrification of the transport and heating sectors combined with active management of demand through smart grid technologies could provide a means of managing wind intermittency in the future. We believe it will be necessary to attain a clear view of the cost/benefits of interconnection in the context of UK energy security and the balancing of services, and recommend that Ofgem conducts research to better establish this view.


128.  In addition to the growth of interconnection, the idea of a European 'super-grid' has gained recent attention. This would connect European electricity markets with renewable energy sources at the boundaries of the system, such as offshore wind from the North Sea and Baltic Seas, hydropower from Scandinavia, and in the long term, solar power from North Africa.[227] Supply and demand would be linked through dedicated very high voltage (HVDC) transmission lines. Various super-grid concepts have been proposed over time. One, the Desertec Industrial Initiative, launched in 2009, would see concentrating solar power systems and wind farms located over 6,500 square miles of the Sahara Desert. Requiring a substantial investment, it could provide up to 15% of Europe's electricity needs by 2050.

129.  The main advantages of the 'super-grid' are similar to those for greater interconnection in terms of ensuring security of supply and creating a pan-European market for electricity. It could also make a significant contribution to European efforts to decarbonise electricity generation, as well as having financial benefits for the North African countries involved. However, there would be a number of challenges. First, there are the technical and engineering difficulties that such a project would entail. The Institution of Engineering and Technology told us that whilst these were surmountable in theory, it was still the case that any such project would be the first of its kind so more work would be necessary to establish feasibility.[228] Linked to this is the skills capacity required to deliver such a project. As the union Prospect told us: "This cannot simply happen overnight and requires a whole set of engineering skill sets in designing, specifying, planning, building, testing and operating the network".[229] A third concern is the regulatory challenge of harmonising grid codes and standards across the various jurisdictions covered by the 'super-grid'.[230] Finally, timely delivery of the network assets may also prove difficult, especially as the deployment of offshore wind in the North Sea is already underway. The Department told us it would not want to see the development of a super-grid delaying its plans for offshore wind.[231]

130.  Some witnesses raised questions about the security of supply benefits that a super-grid would bring. Primary among these are the geopolitical implications of being dependent on North African states for a large proportion of our energy needs.[232] The Institution of Engineering and Technology likened the potential outcome to current concerns over European dependency on Russian gas.[233] Moreover, the Minister acknowledged: "cross-border pipelines in countries where political stability is not always there does present a risk […]".[234] Initial costs were also a significant concern.[235] It was argued that the required outlay would displace domestic investment in network and renewable generation infrastructure.[236]

131.  To date, the Government has taken a cautious approach in engaging with the super-grid proposals. The Department told us it believed: "the costs and benefits […] relative to the alternatives are not well-understood".[237] The Minister said, however, that they were prepared to engage on the issue and that DECC was part of a European Commission working group looking at a potential North Sea project.[238] The Government was also maintaining contact with its EU counterparts on potential plans for a super-grid connection with North Africa.[239] He noted too that the case for investing in the super-grid would depend on its cost-effectiveness relative to other means of ensuring security of supply, such as demand flexibility discussed above, or more sophisticated energy efficiency measures.[240]

132.  The 'super-grid' could make a significant contribution to a low-carbon economy. However, there are major technical and regulatory challenges, while the necessary funding would likely require the redirecting of capital from domestic investment in network and renewable energy infrastructure. The super-grid would have some energy security benefits such as reducing Britain's exposure to fossil fuel price volatility, but would also bring with it new energy security risks, for example, through a new energy dependency on North African countries. We recommend the Government remains engaged at a European level in exploring the super-grid's potential. Any future decision to invest would require a robust analysis of the scheme's cost-effectiveness relative to other means of securing electricity supplies, such as greater demand flexibility.

53   Ev 232 (Scottish and Southern Energy) Back

54   Ibid. Back

55   Ev 103, para 4.2 (ABB), Ev 111, para 15 (Association of Electricity Producers), Ev 149, para 33 (Department of Energy and Climate Change), Ev 164 (Energy Networks Association), Ev 175, para 3.16 (E.ON), Ev 179, para 6 (ESBI International), Ev 212, para 3.1 (Ofgem), Ev 232 (Scottish and Southern Energy), and Ev 237 (Scottish Chambers of Commerce) Back

56   Ev 111, para 15 (Association of Electricity Producers) Back

57   Ev 262, para 32 (Scottish Renewables) Back

58   Q 103 (Scottish Power) Back

59   Ev 237 (Scottish Chambers of Commerce)  Back

60   Ev 179, para 6 (ESBI International) Back

61   Ev 232 (Scottish and Southern Energy) Back

62   Ev 252, para 9 (Scottish Natural Heritage) Back

63   Ev 120, para 10 (Campaign to Protect Rural England) Back

64   Ev 119, para 7 (Campaign to Protect Rural England) Back

65   Ev 149, para 33-35 (Department of Energy and Climate Change) Back

66   Department of Energy and Climate Change, Draft National Policy Statement for Electricity Networks Infrastructure (EN-5), November 2009 Back

67   For example, Ev 164 (Energy Networks Association) and Ev 203, para 13 (National Grid) Back

68   Ev 175, para 3.16 (E.ON UK) Back

69   Ev 232 (Scottish and Southern Energy) Back

70   Ev 111, para 16 (Association of Electricity Producers) Back

71   Ev 227, para 9 (Renewable Energy Association) Back

72   Ev 149, para 29 (Department of Energy and Climate Change) Back

73   Q 154; Ev 227, para 9 (Renewable Energy Association) Back

74   Ev 131, para 33 (Centrica) Back

75   Ev 202, para 6 (National Grid) Back

76   For example, Ev 164 (Energy Networks Association), Ev 171 (Energy Technologies Institute), Ev 227, para 11 (Renewable Energy Association), Ev 258, para 7.3 (Scottish Power) and Ev 270 (Sussex Energy Group) Back

77   Q 3 (Prof Goran Strbac, Imperial College London) Back

78   Electricity Networks Strategy Group, Our electricity transmission network: a vision for 2020, March 2009 Back

79   For example, Ev 110, para 11 (Association of Electricity Producers), Ev 113, para 10 (Arup), Ev 129, para 9 (Centrica) and Ev 232 (Scottish and Southern Energy),  Back

80   Ev 174, para 3.6 (E.ON UK) Back

81   Ev 261, para 22 (Scottish Renewables) Back

82   Ofgem, Transmission Access Review-Enhanced Transmission Incentives: Final Proposals, January 2010 Back

83   Q 307 (Ofgem) Back

84   Q 12 (Dr Michael Pollitt, Judge Business School, University of Cambridge) Back

85   Ev 268, para 2.5 (Prof Goran Strbac, Imperial College London) Back

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

87   Ibid. Back

88   Ev 267, para 1.6 (Prof Goran Strbac, Imperial College London) Back

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

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

91   National Grid, Scottish Power, and Scottish and Southern Energy Open Letter, A fundamental review of the Great Britain Security and Quality of Supply Standard, 24 June 2008 Back

92 Back

93   Based on Ofgem, Addressing Market Power Concerns in the Electricity Wholesale Sector-Initial Policy Proposals, para 1.28-9, March 2009 Back

94   Ofgem, Locational BSUoS Charging Methodology - GB ECM-18, para 1.13, December 2009 Back

95   Ev 267, para 1.5 (Prof Goran Strbac, Imperial College London) Back

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

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

98   Ofgem, Addressing Market Power Concerns in the Electricity Wholesale Sector-Initial Policy Proposals, para 1.14, March 2009 Back

99   Ofgem Press Notice, Ofgem closes Competition Act 1998 case against Scottish Power and Scottish and Southern Energy, 19 January 2009 Back

100   Ofgem, Addressing Market Power Concerns in the Electricity Wholesale Sector-Initial Policy Proposals, para 1.15, March 2009 Back

101   Ibid. Back

102   Ofgem, Locational BSUoS Charging Methodology - GB ECM-18, para 1.13, December 2009 Back

103   National Grid, GB ECM-18 Addendum, November 2009 Back

104   Ev 260 (Scottish Renewables) Back

105   Op. cit. Back

106   Q 88 (Scottish Power) Back

107   Ev 268, para 2.10 (Prof Goran Strbac, Imperial College London) and Ev 278 (P.E. Baker and Dr B. Woodman, University of Exeter) Back

108   Ev 268 (Prof Goran Strbac, Imperial College London) Back

109   Ev 153 (Department of Energy and Climate Change) Back

110   Ev 202 (National Grid) Back

111   Ev 153 (Department of Energy and Climate Change) Back

112   Ev 217 (Ofgem) Back

113   Q 400 (Minister for Energy) Back

114   Qq 166 (Renewable Energy Association), 204 (Association of Electricity Producers) and 282 (Institution of Engineering and Technology); Ev 114, para 13 (ARUP), Ev 175, para 3.17 (E.ON UK) and Ev 180, para 7 (ESBI) Back

115   Ev 223, para 12 (Prospect) Back

116   Q 163 (Scottish Renewables) Back

117   Ev 232 (Scottish and Southern Energy) Back

118   Q 90 (Scottish and Southern Energy) Back

119   Ev 262, para 39 (Scottish Renewables) Back

120   Q 63 (Dr Jim Watson, Sussex Energy Group) Back

121   National Grid, Conclusions Report: GB ECM-17, Transmission charging-A new approach, September 2009 Back

122   Ev 217 (Ofgem) Back

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

124   Q 18 (Dr Michael Pollitt, Judge Business School, University of Cambridge) Back

125   Q 166 (Renewable Energy Association) Back

126   Ev 153 (Department of Energy and Climate Change) Back

127   Q 317 (Ofgem) Back

128   Q 399 (Minister for Energy) Back

129   Q 165 (British Wind Energy Association) Back

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

131   Op.cit. Back

132   Ev 227, para 3 (Renewable Energy Association) Back

133   Ev 217 (Ofgem) Back

134   Ev 147, para 16 (Department of Energy and Climate Change) and Ev 232 (Scottish and Southern Energy)  Back

135   Ibid. Back

136   Ev 261, para 31 (Scottish Renewables) Back

137   Ibid. Back

138   Ev 261, para 32 (Scottish Renewables) Back

139   Ev 196, para 13 (Intergen) Back

140   Ev 232 (Scottish and Southern Energy) Back

141   Ev 148, para 18 (Department of Energy and Climate Change) and Ev 212, para 3.3 (Ofgem)  Back

142   Q 161 (Renewable Energy Association) Back

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

144   Ofgem Press Notice, Ofgem speeds up connections for 450 megawatts of low-carbon generation, 8 May 2009 Back

145   Q 158 (Scottish Renewables) Back

146   Ev 111, para 20 (Association of Electricity Producers), Ev 253, para 15 (Scottish Natural Heritage) and Ev 262, para 34 (Scottish Renewables) Back

147   Ev 131, para 30 (Centrica) Back

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

149   Q 199 (Association of Electricity Producers); Ev 116 (British Wind Energy Association) Back

150   Q 304 (Ofgem) Back

151   Ofgem Letter to the Rt Hon Ed Miliband MP, Transmission Access Review - Third Progress Update, 25 June 2009 Back

152   Department of Energy and Climate Change, Improving Grid Access, August 2009 Back

153   Ofgem, Response to DECC's Consultation on 'Improving Grid Access', December 2009 Back

154   Ev 147, para 15 (Department of Energy and Climate Change) Back

155   Qq 17 (Prof Goran Strbac, Imperial College London) and 21 (Dr Michael Pollitt, Judge Business School, University of Cambridge) Back

156   Ev 196, para 14 (Intergen) Back

157   Ev 111, para 22 (Association of Electricity Producers) Back

158   Q 208 (Association of Electricity Producers) Back

159   Q 314 (Ofgem) Back

160   Ev 217 (Ofgem) Back

161   Ibid. Back

162   Q 19 (Prof Goran Strbac, Imperial College London) Back

163   Ev 112, para 24 (Association of Electricity Producers) Back

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

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

166   Ev 232 (Scottish and Southern Energy) Back

167   Ev 175, para 3.17 (E.ON UK) Back

168   Ofgem, Review of industry governance code-scope of the review, June 2008 Back

169   Ofgem, Code Governance Review: Major Policy Reviews and Self-Governance-Initial Proposals, July 2009  Back

170   Q 304 (Ofgem) Back

171   British Wind Energy Association Briefing Sheet, Offshore wind Back

172 Back

173   The Crown Estate Press Notice, The Crown Estate announces Round 3 Offshore Wind Development Partners, 8 January 2009 Back

174   Ev 150, para 43 (Department of Energy and Climate Change) Back

175   Electricity Networks Strategy Group, Our Electricity Transmission Network: A Vision for 2020, March 2009 Back

176   Q 285 (Institution of Engineering and Technology) Back

177   Ev 189, para 26.2 (Institution of Engineering and Technology) Back

178   Ev 132, para 38 (Centrica) Back

179   Ev 269, para 3.6 (Prof Goran Strbac, Imperial College London) Back

180   Q 38 (Prof Goran Strbac, Imperial College London) Back

181   Q 101 (National Grid) Back

182   Q 178 (British Wind Energy Association) Back

183   Ev 116 (British Wind Energy Association) Back

184   Ev 103, para 5.1 (ABB) and Ev 164 (Energy Networks Association) Back

185   Ev 150, para 40-42 (Department of Energy and Climate Change) Back

186   Ofgem Press Notice, Shortlist for over £1 billion of offshore electricity links announced, 14 December 2009 Back

187   Ofgem, Offshore Electricity Transmission: Consultation on the Enduring Regime, December 2009 Back

188   Ev 218 (Dr Michael Pollitt, Judge Business School, University of Cambridge) Back

189   Op. cit. Back

190   Ofgem Press Notice, Shortlist of over £1 billion of offshore electricity links announced, 14 December 2009 Back

191   For example, Ev 112, para 25 (Association of Electricity Producers), Ev 116 (British Wind Energy Association) and Ev 131, para 35 (Centrica) Back

192   Q 212 (Association of Electricity Producers) Back

193   Q 29 (Dr Michael Pollitt, Judge Business School, University of Cambridge) Back

194   Ev 114, para 16 (ARUP) and Ev 164 (Energy Networks Association) Back

195   Ev 208 (Nuclear Industry Association) Back

196   Ev 205, para 15 (National Grid) Back

197   Ev 114, para 17 (ARUP) Back

198   Ev 150, para 44 (Department of Energy and Climate Change) Back

199   Ev 103, para 5.3 (ABB), Ev 116 (British Wind Energy Association), Ev 131, para 36 (Centrica), Ev 164 (Energy Networks Association), Ev 189, para 25 (Institution of Engineering and Technology), Ev 256, para 4.3 (Scottish Power), Ev 262, para 41 (Scottish Renewables), Ev 271, para 10 (Sussex Energy Group) and Ev 278 (P.E. Baker and Dr B. Woodman, University of Exeter) Back

200   Ev 112, para 26 (Association of Electricity Producers) Back

201   Ev 262, para 43 (Scottish Renewables) Back

202   Ev 103, para 5.3 (ABB) Back

203   Ev 116 (British Wind Energy Association) Back

204   Q 327 (Ofgem) Back

205   Ibid. Back

206   Q 411 (Minister for Energy) Back

207   Q 38 (Prof Goran Strbac, Imperial College London) Back

208   Q 330 (Ofgem) Back

209   Ev 214, para 5.3 (Ofgem) Back

210   Ev 103, para 6.1 (ABB), Ev 132, para 41 (Centrica), Ev 135, para 14 (Chemical Industries Association), Ev 151, para 50 (Department of Energy and Climate Change), Ev 164 (Energy Networks Association), Ev 176, para 3.20 (E.ON UK), Ev 205, para 19 (National Grid), Ev 237 (Scottish Chambers of Commerce) and Ev 275 (Town and Country Planning Association) Back

211   Ibid. and Ev 104, para 1.5 (Areva), Ev 112, para 28 (Association of Electricity Producers), Ev 116 (British Wind Energy Association), Ev 208 (Nuclear Industry Association), Ev 214, para 5.1 (Ofgem), Ev 229, para 29 (Renewable Energy Association) and Ev 278 (P.E. Baker and Dr B. Woodman, University of Exeter) Back

212   Centre for Sustainable Energy and Distributed Generation, Economic and Environmental Impact of Dynamic Demand, November 2008 Back

213   Poyry, Impact of intermittency, July 2009 Back

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

215   Ev 176, para 3.20 (E.ON UK) Back

216   Q 41 (Prof Goran Strbac, Imperial College London) Back

217   Ev 176, para 3.20 (E.ON UK) and Ev 278 (P.E. Baker and Dr B. Woodman, University of Exeter) Back

218   Ev 218 (Dr Michael Pollitt, Judge Business School, University of Cambridge) Back

219   Ev 105, para 5.2 (Areva) and Ev 114, para 20 (ARUP)  Back

220   Ev 180, para 8 (ESBI) and Ev 205, para 18 (National Grid) Back

221   Ev 135, para 13 (Chemical Industries Association) Back

222   Ev 214, para 5.2 (Ofgem) Back

223   House of Commons Business and Enterprise Committee Eleventh Report of Session 2007-08, Energy prices, fuel poverty and Ofgem, July 2008, HC 293 Back

224   Ev 218 (Dr Michael Pollitt, Judge Business School, University of Cambridge) Back

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

226   Q 41 (Prof Goran Strbac, Imperial College London) Back

227   Ev 151, para 51 (Department of Energy and Climate Change) Back

228   Q 295 (Institution of Engineering and Technology) Back

229   Ev 223, para 13 (Prospect) Back

230   Ev 257, para 5.1 (Scottish Power) Back

231   Ev 151, para 53 (Department of Energy and Climate Change) Back

232   Q 41 (Dr Michael Pollitt, Judge Business School, University of Cambridge) Back

233   Q 295 (Institution of Engineering and Technology) Back

234   Q 428 (Minster for Energy) Back

235   Q 39 (Dr Michael Pollitt, Judge Business School, University of Cambridge); Ev 176, para 3.21 (E.ON UK) Back

236   Ev 182 (Helius Energy) Back

237   Ev 151, para 52 (Department of Energy and Climate Change) Back

238   Q 425 (Minister for Energy) Back

239   Ev 151, para 52 (Department of Energy and Climate Change) Back

240   Q 429 (Minister for Energy) Back

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