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Memorandum submitted by Centrica (FBEN 30)
Centrica's
key themes: · Centrica
supports the plans developed by the industry with Ofgem and government to
facilitate transmission investment crucial to meeting 2020 targets. Co-ordinated
and joined up thinking is needed across networks to ensure a coherent and
consistent approach to meeting the competing policy objectives of security of
supply, carbon reduction and affordability for customers. · It is
critical that these plans are taken forward ahead of user commitment to meet
short and long term objectives · Government
needs to more clearly define its role in the regulatory process while also
recognising its role in promoting a stable regulatory framework that encourages
investment and protects customers. · As network costs escalate and fuel poverty increases, networks must provide value for money and earn rewards that correspond to the performance they deliver. Networks must work more closely with suppliers and customers to support effective competition in generation and supply
1. In this response to the request for written evidence on the Future of Britain's Electricity Networks, the bulk of our points are in the main body of the response below. We have then made some additional observations in response to a number of the questions posed by the Select Committee.
2. The competitive electricity market faces significant challenges in the next decade and beyond. The market needs to bring low carbon energy to heat and light customers' homes while enabling them to benefit from competitive prices, new technologies and products to help them be more energy efficient. For this to happen the generation mix needs to be transformed as new low carbon generation replaces older units. There is a need for a balanced portfolio of generation technologies to reduce dependence on any single source or technology and effectively manage wind variability.
3. Electricity networks have a crucial role to play in supporting and enabling these developments. As the network companies are monopolies, regulated in the public interest, government policy and regulation play a key role in driving their behaviour. This requires a regulatory framework that gives them a reasonable return in exchange for the risks they bear and the performance they deliver while ensuring customers are protected from unnecessary costs. To meet the 2020 and 2050 targets, Government and Ofgem also need to be proactive to reduce barriers to the capital investment in the networks that is required to support the connection of significant amounts of new generation of all types.
4. Government Policy initiatives will reshape the power sector by 2020 to meet renewable energy and low carbon targets. The variable nature of wind means that substantial amounts of flexible plant will still be required, though operating at lower load factors. The current wholesale power market design was not developed to cope with the issues this mix is likely to cause, thus market design needs to be fully considered.
5. Centrica and its customers have a huge stake in the
future of
6. Centrica is investing heavily in new generation, both
conventional and renewable, on and offshore. This reinforces our concern that
the vision for the future of
Transmission investment to meet 2020 targets is urgently required
7. The challenges raised in the electricity sector by the government's commitment to meet the 2020 targets highlight the need for a more joined up approach to government policy and the regulatory framework. Solving the trilemma of security of supply, climate change and affordable prices to customers is key. The networks cannot fully play their role without government and regulatory support to help unblock barriers (for instance, planning requirements) or provide assurances that they will recover their legitimate costs. We will continue to need a regulatory process that enables review and challenge the of networks' business plans, ensuring appropriate incentives to invest whilst not unduly exposing customers to unnecessary cost.
8. Focusing on attainment of the 2020 targets has highlighted the issues in transmission investment which are delaying the connection of new generation, including renewables. Centrica has participated in a study led by the Energy Network Strategy Group (chaired by DECC and Ofgem) which has identified a range of transmission projects deemed to be 'low regret' proposals (i.e. very likely to be needed in the future.).
9. Centrica supports the study's conclusions that reinforcements can be delivered to the required timescales, provided the identified projects are taken forward immediately and the planning consent process facilitates network development. These proposals will accommodate 45GW of new generation (including 34GW of wind), estimated cost £4.7bn. Ofgem should introduce regulatory arrangements to support this programme and facilitate timely capacity for new generation.
Government guidance and an effective regulatory process are both essential
10. Better regulatory processes are needed to reduce the risk that the failure of network companies to deliver new capacity or better manage existing capacity, contributes to failure to meet environmental targets. Ofgem's review of network monopoly regulation is timely. Given the special importance today of cost effective capital investment, the RPI-X review may well conclude that significant changes are required to the current approach to ensure the new policy challenges are met in a way that better reflects the interests of all stakeholders.
11. Government policies are helping to shape the future low carbon energy supply mix by (for example) decisions on new coal plant, facilitation of new nuclear and measures such as the Renewables Obligation and Feed-in Tariffs for microgeneration. It makes sense therefore for government to provide high-level guidance helping ensure networks are developed in a way that is consistent with its vision of the competitive electricity market.
12. A more explicit government role would also acknowledge that the scale and type of future generation investments will reflect both the environmental targets and the policies and support mechanisms put in place by government to help meet them. Potential investors have to factor in risks around government policy as an essential element in any large power generation investment, and as such, need consistency of approach.
13. As costs change and technologies evolve the regulatory process should allow government guidance to be combined with customer requirements and demand for new network capacity. Views on the most cost effective forms of low carbon generation will change and user requirements should remain a key input to network planning decisions. The future regulatory process may look substantially different from the current price control model. Centrica is working with other stakeholders as part of the RPI-X@20 review to determine what this model might be.
Networks must be more focused on meeting their customers' needs
14. The processes for determining investment solutions may vary between transmission and distribution. In transmission, National Grid (NG) is an independent system operator and there are many large power market participants whose plans help shape NG's investment priorities. By contrast, distribution companies are mostly owned by major participants in generation and supply and there is less independent user engagement in shaping the companies' investment plans. The regulatory process should reflect these different dynamics.
15. As investment in
16. DNOs must fully explain the basis for these proposed price increases setting out the business case for the new capital investments required. DNOs have often failed to spend their capital expenditure budgets, and current price control evidence suggests they may have been excessively rewarded for some activities (e.g. initiatives to reduce electricity losses), and that they have earned returns significantly higher than the allowed cost of capital.
17. In terms of the regulatory framework going forward, it is essential for British Gas to be better able to manage and predict network costs, enabling us to respond effectively to customer demand for innovative, competitively priced retail offerings and to make energy more affordable for our customers. Currently DNOs provide only limited transparency and predictability of future charges leading to real costs for suppliers in providing the fixed price offerings many customers prefer. This position will be improved by Ofgem's work to require electricity DNOs to charge suppliers according to a common methodology.
A decision on the introduction of smart metering is urgently required
18. In considering the challenges networks face in future, smart metering will be an essential tool to help reduce unnecessary investment and facilitate demand side response. The information gained from smart meters may have a profound impact on the shape of the networks in the long term. A decision from government confirming the mandate and the model for the roll-out of smart metering is therefore a key priority. Once this investment programme has begun, we can then begin to plan for the development of smart grids, and a world where we have more intelligent networks (reducing costs and improving customer service) and better capacity planning and optimisation in network operations.
Notes on specific questions:
Q1: What should the Government's vision be for Britain's electricity networks, if it is to meet the EU 2020 renewables target, and longer-term security of energy supply and climate change goals?
19. In order for Government to meet the 2020 decarbonisation targets, there will need to be a significant amount of renewable generation connected to the network. We believe that the current grid is not fit for purpose and needs investment to meet the demands that, new generation, distributed generation and microgeneration will place upon it.
20. The longer term vision should be of a coordinated UK plc network strategy for GB - both Transmission and Distribution. Whilst this does not assume the same approach for both, or even an immediate decision, a joined up approach reflecting the interactions between different parts of the network is essential. However, in formulating this vision, there is a need to recognise the overall direction - is it towards a 2050 "big" transmission "small" distribution network scenario or vice versa where local small and/or distributed generation has had substantial growth? The LENS and ENSG work will be invaluable in informing this debate.
21. In the medium term the requirement is to deliver new build to enable renewables targets (and business as usual requirements) to be met, but 2020 is not an end in itself.
22. There are features of the current regime which we believe have merit, and should persist into the future. The vision needs to acknowledge that the proper and flexible provision of services may entail a combination of natural monopoly and competitive processes.
23. Realistically, we believe that the GB System Operator function should remain a geographic monopoly, as the complexities associated with changing this are likely to be both costly and inefficient - we would envisage the same for the major existing networks. However, there is merit in facilitating independent distributors competing for new build/infill networks.
24. In respect of the regime to support short and medium term connection of on and offshore renewables, a coordinated on and offshore regime is needed, covering both the network and charging requirements. It is essential that the Offshore Transmission Operator (OFTO) regime is effective and efficient - providing timely offshore connections, with lower operation and maintenance costs for developers.
25. Centrica believes that significant amounts of offshore wind can be delivered assuming the right political, regulatory and fiscal framework is in place.
Q2: How do we ensure the regulatory framework is flexible enough to cope with uncertainty over the future generation mix?
26. The future generation mix will be determined by a combination of the signals sent to investors through energy commodity prices and the policy framework, including the incentive mechanisms, that Government and Ofgem is building in to the energy market. As the relative attractiveness of different types of new build generation change over time, the process for regulating the networks needs to able to deal with these uncertainties and place the risks associated with different network investments where they are best placed to be managed.
27. User commitment is important in this context because through this principle customers are protected from the risk of stranded network investment if a user underwrites the cost of the investment. Where users are prepared to take on the investment risk, the networks should be confident and able to provide the necessary capacity. However, experience with electricity transmission has shown that due to the lead times sometimes required for new capacity to be delivered, network investment can be unnecessarily delayed. A new regulatory framework needs to find better ways of managing these risks.
28. Some investments, as we are seeing now in electricity transmission, may need to take place ahead of firm demand commitments. However, in order to protect the interests of consumers, we would not advocate the indiscriminate application of this principle to both transmission and distribution and we also believe that such investment , ahead of user commitment, should be carefully scrutinised as is the case with the ENSG process.
Q3: 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.
29. In considering these crucial questions, in particular, the impact on costs of constraints, it is essential to recognize that both connection capability and capacity need to be addressed.
30. Centrica believes that access arrangements should support the connection of renewable generation, whilst not undermining investment in existing and new conventional generation, in particular as variable renewable generation requires conventional back-up. Our view is that "connect and manage" is the only practical way forward in the timescale, but the resulting constraint costs will need to be effectively managed.
31. In addition, as nuclear and most renewables have negligible short run marginal costs, they will seek to generate whenever they can. This could lead to a significantly increased volume of must run generation and reduced opportunities for flexible plant to capture value. To address this uncertainty, support mechanisms need to be considered to ensure the right plant is available as required with incentives to move load to times when the wind is blowing. This may be dependant on intelligent control of installed smart metering.
32. Current transmission investment arrangements have resulted in transmission owners investing in additional transmission capacity only in response to signals from generators (user commitment). Generation plant build times of c. 4 years and transmission capacity lead times of c. 7 years (with delays (primarily) due to planning and consents), together with an increase in connection requests from wind and new nuclear have resulted in a queue stretching beyond 2020.
33. The transmission owners have not been allowed to invest strategically, ahead of the predicted growth in renewables, and this is now impacting their ability to provide connections in the required locations. GB needs a co-ordinated blueprint for grid investments to 2020 and beyond. The ENSG study provides a co-ordinated anticipatory investment plan and could form the basis of this blueprint. This work should be leveraged immediately as regulatory uncertainty around this issue has the potential to deter investment and ultimately impact GB's security of supply (power). A coherent and cohesive set of network incentives is needed to support investment and government objectives in a holistic manner.
Q4: What are the issues the Government and regulator must address to establish a cost-effective offshore transmission regime?
34. Currently, the offshore activity is separated into two groups of projects: Round 1 & 2 and the longer term, Round 3 projects.
35. In respect of Rounds 1 and 2, whilst we continue to have reservations, we support the current Ofgem and DECC proposals. These need to be implemented to plan and carefully monitored, to avoid any additional regulatory uncertainty deterring investors.
36. For Round 3, we believe that a more co-ordinated and strategic approach is called for. On this basis, we believe that a careful review of the processes implemented for Rounds 1 & 2 is required and urgent discussions are needed on how this process can be improved for Round 3. Consideration could be given to zonal approaches or allowing developers to design and build the transmission assets in advance of the tendering process.
37. The
economics of many Round 2 projects have suffered as a result of increases in
project costs (due to increases in commodity costs like steel and copper, but
also exchange rate movements since most components are bought in euros). Increased cost of capital is also pushing
rates of return below acceptable levels. 38. Another cost pressure on offshore wind farm construction has been the changed assumptions for charging of offshore transmission network use of system charges (TNUoS). Initial assumptions used for projects (and for the derivation of ROC values) were that generators would pay TNUoS charges as though they had connected onshore, i.e. all offshore cable and substation costs would be socialised across generators and consumers. Over the past year Ofgem/National Grid's proposals have changed, such that offshore substation and cable costs will be targeted directly at the offshore generator. This change has a significant impact, in some cases increasing offshore transmission costs by a factor of ten or more.
39. Finally, whilst there is a clear need for regulatory stability to give investors confidence in the regime, we believe that a review of the Round 1 & 2 process should be arranged after the first few tenders to ensure that Round 2 projects can also benefit from the improved Round 3 process should they wish to do so.
Q5: What are the benefits and risks associated with greater interconnection with other countries, and the proposed 'supergrid'?
40. In terms of the formation of a supergrid, it is important to recognize this is not a panacea and doesn't mean that a move to a world of 100% generation from wind would be possible, neither would it negate the need for a balanced portfolio of different generation types to support the more variable supply sources.
41. Looking forward, we believe that greater
interconnection with other markets will be a key feature, offering significant
benefits and helping to diversify risk. These benefits include improvements in security
and diversity of supply, providing additional options to balance the
42. On a larger scale the discussions around a supergrid offer interesting opportunities. As well as the benefits of greater interconnection set out above, this could provide multiple routes to market for offshore renewables/wind farm developers. However such benefits will need to be balanced against the risk that the most efficient inter-country transfer may not be achieved due to wind variability causing difficulties in commercial/trading arrangements and the fact that power is likely to follow the route to the highest priced market.
Q6: What
challenges will higher levels of embedded and distributed generation create for
43. Distribution networks do need to support the development of more small scale and distributed generation. There is much that can be done within the existing policy frameworks to facilitate small scale generation connecting to the networks in ways that minimize resulting network reinforcement requirements (for example, through charging methodologies that send locational signals to generators to encourage them to connect to the network where it is most cost effective for customers). To the extent further investment in distribution networks is required to support these further developments of small scale generation, the distribution network operators should make the case for it as part of the current distribution price control which will lead to new rates for customers for distribution costs from 2010.
Q7: What are the estimated costs of upgrading our electricity networks, and how will these be met?
44. The increases needed in network costs will be significant and it is essential to ensure that good value is secured for customers. The proposed increases in regulated expenditure must be reviewed and challenged robustly as part of the price control processes and only efficient costs allowed. However, these investments will have to be made if Government is serious about meeting environmental targets and the other aspects of the "tri-lemma" referenced above. It should also be recognised that a proportion of the funds would need to be spent in any case due to requirements for capital expenditure on the grid as part of the natural investment cycle.
45. Given the costs associated with upgrading our electricity networks will be considerable, clarity is needed on how the costs will be distributed equitably given the current debates around charging methodologies.
March 2009 |