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Memorandum submitted by E.ON (FBEN 29)
Executive Summary · Britain's electricity networks are key to the successful achievement of government energy policy objectives. · Long term regulatory stability is essential to give confidence to and ensure investment in networks. · The success of the new planning process under the Planning Act 2008 will be key to the delivery of major energy network projects in future. · Distribution network operators (DNOs) have a more active role to play in the facilitation of a low carbon economy, and we look forward to engaging with Ofgem, government and other stakeholders to develop robust, long term solutions. · The regulatory framework must be aligned with government energy policy goals. We welcome Ofgem's and DECC's support for a strategic approach for transmission network investment, and for greater innovation in network design and investment incentives, which will help facilitate this. · We
believe that the strategic transmission investment incentive mechanism should
allow the transmission companies greater flexibility in making their investment
decisions. The transmission companies must start developing their planned
investment now to give the best chance of providing a network that will be
sufficient for the · We
recommend the consideration of a similar strategic approach for distribution,
which is at the beginning of a prolonged period of asset replacement. A clearer
vision of the future energy network landscape of the · E.ON believes that smart networks can bring opportunities to networks businesses, but DNOs now need to build up their capabilities, test potential solutions and understand the benefits and risks. RPI-X has been successful at driving costs down, but now needs to be broadened to allow DNOs to develop ready for the challenges they now face. · The network businesses have in recent years introduced a very effective programme of innovation, but there is a need for ongoing development of the framework to encourage project replication and acknowledge the inherent risks associated with emerging technology application.
1 Introduction 1.1 E.ON 2 General remarks 2.1 E.ON 2.2 We welcome the opportunity for distribution network operators (DNOs) to take a more active role in the facilitation of a low carbon economy, and are keen to help develop a robust framework which enables a more proactive approach by DNOs and provides appropriate funding, as well as taking account of the risks and uncertainties that networks businesses face in the DPCR5 period and beyond. Aligned with this, we welcome Ofgem's and DECC's agreement with the industry that a strategic approach is required for transmission network investment, along with greater innovation in network design and investment incentives. 3 Answers to specific questions What should the Government's vision be for 3.1 Effective electricity networks will be
key facilitators in the delivery of our energy policy goals. The priority
should be to ensure there is sufficient investment to maintain secure supplies
to consumers, that networks are capable of incorporating low carbon
technologies at all scales, and that the investment required is delivered
efficiently and does not impose excessive costs on customers. The expectations
of 3.2 Where there are clear targets and reasonable certainty where investment will be located (as with on and offshore wind and nuclear), the regulatory framework needs to support the required investment and its delivery in good time. However, in other areas, where there is more uncertainty (for example in respect of the extent of distributed and microgeneration), the regulatory framework needs to allow companies to commit investment to create options for the future. 3.3 Many network assets were installed in the 1950s and 1960s and are now reaching the end of their lives, and the cost of replacing them and of recruiting and training the skilled workforce that will be needed to carry out this work over the next 15 or 20 years are considerable. Companies must be appropriately rewarded for this massive investment programme, within a stable regulatory framework that will enable them to attract equity funding in today's less favourable economic climate. 3.4 The role of the electricity distribution companies could help with the integration of low carbon activities, potentially combining smart network features that could help facilitate generation connection and network diagnostics, with additional energy management requirements. 3.5 The degree of flexibility suggested by
the range of scenarios under consideration is too great for effective
engagement. In order to deliver the desired · A narrower range of outcomes for likely generation mix (central vs. distributed, level intermittency, geographic dispersal etc). · A consistent view of customer demand developments, particularly electric vehicles and electric heat pump adoption. · A clearer view of 'end to end' energy delivery roles and responsibilities, dealing with, for example the application of demand side management technologies. 3.6 The Department for Energy and Climate Change (DECC) reconstituted the Electricity Networks Strategy Group (ENSG) in 2008 to consider the transmission network requirements for 2015, 2020 and 2030. The ENSG has reported its recommendations for least regret and low regret investments required to provide the necessary transmission system to facilitate the 2020 renewables target. We supported this work and participated in the Transmission Project Working Group that prepared the report to the ENSG. We agree with the recommendations contained in the report. In particular we believe that transmission companies should be permitted to commence immediately with pre-construction work on the investment projects identified, in order to provide the opportunity to meet 2020 targets. How do we ensure the regulatory framework is flexible enough to cope with uncertainty over the future generation mix? 3.7 Given the complexity of the issues discussed above and the urgency of action to meet 2020 targets, there may not be a single "ideal" solution in the form of a regulatory mechanism or incentive. The framework will however need to accommodate three key mechanisms: · To grow capabilities in relatively short timescales, resource also needs to be funded via the price control for engagement and development with developers and local authorities, similar to "incubation" funding provided to start-up companies. This should encapsulate a more proactive stance from networks in supporting future projects but also working with them to innovate in new commercial and technical solutions for future energy policy. This should be shielded from the RPI-X cost control framework to actively encourage development. · To encourage the construction of demonstration projects and key partnerships early in the DPCR5 period, supported by an innovation incentive mechanism and the DG incentive. · To support the transposition to business as usual, minimising the unit cost of application, but recognising that this will add to the levels of business risk within the network companies. This "risk premium" may be best recognised as an explicit element of the company's financing costs. 3.8 A fundamental point that must be recognised is that as DNOs will face increased risk in a number of ways, including financing capacity for smart schemes that fail, interaction with regulatory incentives - losses, Customer Interruptions (CIs) or Customer Minutes Lost (CMLs). DPCR5 is making steps in the right direction, and is likely to deliver a more flexible treatment of costs, although the treatment of losses needs more consideration, particularly since in the current form it would penalise "smart" networks where capacity utilisation is increased. 3.9 There will be additional risk to companies (for example, additional capacity may be required on top of "smart" solutions), and the framework must recognise this and find a pragmatic way to assign this risk between companies and customers, recognising the longer term benefits to the UK as a whole. Ultimately, the framework has to ensure investors stand a reasonable chance of making a return from investing in new approaches and technologies - "a fair bet" as some commentators have observed. 3.10 Proposed changes by Ofgem to remove cost-incentives that dissuade companies from pursuing operating cost solutions vs. capital investment programmes will also help significantly. 3.11 The framework must also recognise the need to provide for network developments for both known connection projects, and also the expected large number of unknown connection and development requirements. 3.12 Tthe regulatory framework for transmission should also be aligned with government energy policy goals. Ofgem has recently consulted on transmission owner (TO) investment incentives to provide a funding mechanism for the necessary transmission network reinforcement to facilitate transmission capacity requirements for the 2020 renewables targets. The mechanism relates to the low and least regret investments identified in the ENSG transmission project working group report. The investment incentive mechanism in principle should allow the TOs greater flexibility in making their investment decisions, alongside the price control review process. Consequently Ofgem's role in approving investment in the transmission system could be reduced. What are the technical, commercial and regulatory barriers that need to be overcome to ensure sufficient network capacity is in place to connect a large increase in onshore renewables, particularly wind power, as well as new nuclear build in the future? For example issues may include the use of locational pricing, or the availability of skills. 3.13 The barriers relate to the points discussed
above, most importantly the high level of uncertainty and the ability of the
regulatory framework to handle this whilst incentivising investment and keeping
prices at efficient levels. For example, there is no common commercial
framework to handle interactions between customers and DNOs for control of
generation and demand side management, and indeed no clarity on whether there
should be direct contact or via an intermediary. Likewise, there is little
experience in the 3.14 The development of an industry wide common set of assumptions for use by the distribution companies would certainly reduce the degree of uncertainty, and consequently encourage earlier physical engagement. 3.15 As for transmission, this would need acceptance by Ofgem of some investment ahead of need, which the current framework fails to accommodate. 3.16 The success of the new IPC planning process under the Planning Act 2008 will be key to the delivery of major energy infrastructure projects. The national policy statements for energy infrastructure are therefore important documents to get right to enable the investment needed. 3.17 Locational pricing is a prerequisite for the long term efficient economic development of the transmission network because it incentivises generation and demand to be located near to each other thus reducing transmission losses and CO2 emissions, and is therefore in the interests of the consumer and the environment. Optimising the use of the transmission system, through a form of 'connect and manage' being considered under the transmission access review, is important to the connection of new renewables in the short to medium term. Long term regulatory certainty however is essential to give confidence to and ensure investment in the network and generation with longer lead times, such as nuclear. Regulatory certainty will provide the investment needed in the supply chain and increases in the skilled resource that will be required for delivery of the network infrastructure and new generation. 3.18 Proving new technology for the deployment in
the What are the issues the Government and regulator must address to establish a cost-effective offshore transmission regime? 3.19 The need for regulatory clarity and stability is key. The introduction of the proposed offshore transmission regime should therefore not be delayed. Whilst it can be implemented for transitional projects, DECC and Ofgem have yet to demonstrate that the regime will work as hoped to provide offshore strategic network investment. A route map of the application of the competitive tender process for the delivery of round three projects and later round one and two projects that do not qualify for transitional status would be an important step to providing industry confidence. If this can be proven the benefits of competition should help to deliver cost effective investment, much needed sources of capital and delivery capability to meet the scale of investment predicted for the network and generation offshore. What are the benefits and risks associated with greater interconnection with other countries, and the proposed 'supergrid'? 3.20 The main benefit of greater interconnection is that the increased trading between the two connected systems will allow generation to be used more efficiently and reduce the total volume of capacity required to meet demand if peaks are at different times. A potential benefit of greater interconnection is the access to additional reserve generation would help to offset increased volumes of intermittent generation, although our studies suggest this effect is limited as large volumes of wind generation also occur in north western Europe which is often subject to similar weather conditions. Interconnectors are expensive and the trading benefits have to provide through usage charges an adequate return on the investment. 3.21 A super grid connecting offshore wind farms to adjacent countries is an exciting proposal but it is unclear whether this is the most cost effective route for connecting new offshore wind. Timely delivery of the supergrid will be an issue. For example, round three offshore windfarms should not be delayed because the connection of a zone is dependent upon a wider interconnection project. What challenges will higher levels of
embedded and distributed generation create for 3.22 The electricity network has in general been designed to transport power from large central generators through the transmission and distribution grids to the end customers. Investment in the distribution network will be important as networks move from this passive, one directional design to more active networks, with the interaction between embedded generation and potential growth in demand side management. 3.23 Technical challenges include voltage control, the management of thermal limits of lines and cables and the operation within plant fault level ratings, whilst optimising to ensure demands such as vehicle charging, and DG inputs are all integrated into the distribution network. The extensive development and integration of control and telecommunications systems will become increasingly important. 3.24 Contractual challenges include risk allocation, where for example a local generator is relied upon in preference to the investment in additional network capacity. What are the estimated costs of upgrading our electricity networks, and how will these be met? 3.25 For transmission, the ENSG 2020 transmission network report indicates capital expenditure of £4.7bn, but that savings of £850m can be made by commencing the pre-engineering work now to enable timely delivery. This will reduce the amount of more expensive offshore network investment that may otherwise be required. 3.26 We are still assessing the cost impact for
distribution networks within E.ON How can the regulatory framework ensure adequate network investment in light of the current credit crunch and recession? 3.27 The regulatory framework must allow adequate cost of capital to attract the substantial funding required and must recognise the long term nature of network investments. In the face of increasing capital requirements, companies need to be able to maintain a stable financial position and credit rating, and not be forced into "novel" debt-base financial engineering by an inadequate recognition of the cost and value of equity in the allowed regulatory return. In addition, as innovation is increased, the risk taken by businesses will increase, and this must be reflected in the return, with an emphasis again on the importance of equity. Finally, the framework must recognise that new ideas by their nature sometimes fail and not unduly penalise companies which are trying to innovate. How can the regulatory framework encourage network operators to innovate, and what is the potential of smart grid technologies? 3.28 The existing regulatory framework has been very effective in encouraging research and development activity amongst the network companies, and has in parallel provided some stimulus for network related programmes within our universities. This approach should certainly be continued, but supported by a regulatory framework that encourages not just the initial innovation, which is beneficial, but importantly the replication of innovative developments in pursuit of a lower carbon model. Please see paragraph 3.7 and following paragraphs for more specific proposals for electricity distribution regulation. 3.29 Whilst TO investment incentives should
facilitate the necessary investment, this will be underpinned by the price
control arrangements on transmission and distribution companies as well as the
competitive tender process for awarding 20 year offshore transmission
licences. Long term regulatory certainty
will give added confidence and minimise the risk relative to other investment
opportunities, so that the 3.30 The potential for 'smartgrid' technologies is considerable and the benefits could span distributed generation facilitation through active controls, network security improvements through automation and diagnostics, and network utilisation through the application of demand side management techniques. Is there sufficient investment in R&D and innovation for transmission and distribution technologies? 3.31 We believe there is, at least in the early stages of development, sufficient investment and the Innovation Funding Incentive has been very successful. 3.32 Whilst there is an R&D allowance under
the transmission price controls, the ENSG transmission report suggests using
HVDC technology and series reactors, which are new technology for deployment
onshore in the What can the 3.33 Experience from the feed in tariff in 3.34 German offshore wind deployment has progressed but is limited by the level of technology currently available to facilitate deployment of large scale offshore wind in deep waters. 3.35 Some countries are less focussed on ensuring that network investment has a clearly demonstrable economic justification. They may take a more probabilistic attitude to planning and allow or even incentivise investment in strategic infrastructure projects ahead of need. Ofgem is starting to do this, but its approach is to develop a carefully calibrated incentive. This may be appropriate, as it leaves some risk with the network company and provides an incentive for National Grid to engage with developers. However, it may also mean capacity will not be built as quickly. 3.36 A roadmap for how to achieve a vision could be useful if Ofgem then had to take this into account when assessing efficiency of investment. This approach is, for example, now being actively considered by the Californian legislature[2].
March 2009
[1] Regulatory capex based on DPCR4 cost allocation methodology. [2] Californian Senate Bill 17 (Padilla); "Electricity: smart grid systems." |