Memorandum submitted by Dr Michael Pollitt,

ESRC Electricity Policy Research Group, Judge Business School (FBEN 6)

 

· 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?

· How do we ensure the regulatory framework is flexible enough to cope with uncertainty over the future generation mix?

 

A useful starting point for a discussion of the future of GB's electricity networks is Ofgem's LENS report which outlines five scenarios for the future of the UK electricity network[1]. The LENS scenarios from Ofgem describe five very different electricity networks in 2050, ranging from a heavily reinforced scenario with 'bigger' transmission and distribution networks (Big T&D) than at present sized to cope with the variability of large renewable plant, particularly wind farms to a micro-grid based scenario (Micro-grids) with lots of local generation and less strongly inter-connected local grids, based on local biomass, wind and solar.

 

Another important starting point is the idea that when it comes to electricity policy we should be thinking in terms of the efficient delivery of energy services (heating, lighting, power etc) rather than in terms of vertical structure of the current electricity supply industry (generation, transmission, distribution and supply). The question is not how best to configure the electricity network, but how best to ensure reasonable demands for energy services are met most efficiently. This encourages to think in terms of appropriate organizational forms for such delivery and to be open to potentially radically different combinations of assets which might best deliver services (e.g. heat networks, local generation etc.).

 

It is worthwhile starting with a number of basic principles for the future regulation of networks.[2]

 

First, there should be a presumption that regulation in the future will involve more deliberate engagement between buyers and sellers of network services (or their representatives). Stephen Littlechild has discussed the success of such policies in the electricity systems in North and South America (so called negotiated settlements).[3] The UK has been experimenting with this in airports with some success (where it is known as constructive engagement). Given the uncertainty about the future, creating appropriate fora for negotiation between the parties is crucial as a way of handling this uncertainty and managing the complexity of the task of approving investment plans faced by the regulator.

 

Second, regulation should remain committed to making good use of competitive mechanisms wherever possible and to facilitating innovative entry into the sector. In electricity generation and supply we expect large amounts of innovation to help us to meet our ambitious climate change targets. Electricity networks involve substantial investments by themselves, but even more importantly can influence (via their flexibility/inflexibility) the generation/supply investments that they support. They need to be incentivised to encourage new entrants and be open to the possibility that the current natural monopoly model of networks may not be optimal by 2050.

 

Third, the academic literature and practical experience has already established that differentiated pricing has a key role to play. The arrival of smart metering throughout the distribution system will offer significant potential for demand response both in the short and long run at the household and commercial levels. Such demand response requires the use of differentiated pricing in space and through time for all electricity customers. Customers may, of course, choose not to be exposed to such variations directly (by choosing time invariant contracts) but the incentives for energy service providers to match load to intermittent (or indeed inflexible) generation should exist.

 

Fourth, keeping technological options (and hence all the scenarios) open has a lot of value initially. We just don't know at this stage what the best network configuration is for 2020 or 2050, not least because of price, policy and technological uncertainty. Different configurations have strengths and weaknesses. However to begin with we can achieve demand reduction and increases in renewable generation without radical changes to energy networks. This gives us space to experiment with different technological options and organisational forms. We should take this opportunity because it has a high initial option value.

 

Fifth, the climate change agenda needs to be consistently pursued through all aspects of regulation. It is important to stress that rational consistency of policy is key to delivering energy services at least cost. This requires a single price of carbon and a consistent subsidy framework delivered with commitment over the life of investments. We are some way from achieving this difficult policy aim. At the moment planned network investment is being made in an environment of high uncertainty about the future financial incentives that will be available. As with generation investments it is important that network investments face a more consistent policy framework going forward than at present.

 

An additional starting point, is to point out that it is possible imagine linear combinations of the scenarios (this is different from the Multi-purpose networks scenario in LENS). Thus different distribution network areas might follow different paths towards achieving our overall climate targets and this might be a desirable outcome given their different electricity generation and demand characteristics.

 

 

· 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.

 

An increase in large scale inflexible central generation (over the current level) would mean a need for either more flexible demand or more storage. Flexible demand is helped by clear price signals to loads. It seems clear that nodal pricing throughout the transmission system (like in the PJM market in the US) and additionally nodal pricing within the distribution system (as is being partially implemented in the South West (WPD)) would seem to be important to provide finely differentiated incentives which could help manage demand and incentivise least system cost location of distributed and micro-generation.

 

Consideration might also need to be given to storage technology which might complement extra wind on the system. It would be possible to invest in a significant amount more pumped storage hydro. Careful evaluation of the value of such water (which may not be privately economic if it reduces the price differentials across time and hence the arbitrage opportunity) would need to be made. David MacKay[4] notes that several good sites are already identified for this capacity. Similarly there are possibilities for dumping excess wind power into heat (via electrical elements in hot water tanks) which are being investigated in Scotland (and happens in Denmark) but would require appropriate connections and incentives. However this might be a cheap alternative to building new storage capacity.

 

 

· What are the issues the Government and regulator must address to establish a cost-effective offshore transmission regime?

 

Ofgem are making substantial progress with this. The move to have auctions for transmission capacity is a positive one, which should ensure least cost new build of plant. Littlechild notes the success of auctions for new transmission wires in Argentina[5] and Pollitt noted the cost-reducing value of contestability in transmission wire building in Chile[6]. This process should cause significant new entry into the transmission market in the UK. Care must be taken on where transmission links are connected into the existing grid as this generation will be intermittent and large scale. It is also important that auctions are monitored to ensure competitiveness and that bidders deliver on their winning bids. Clearly lessons from the private finance initiative need to be learnt to avoid only one effective bidder at the final stage. However given the standard nature of investment in each case, the prospects for this form of competitive process would seem to be good.

 

· What are the benefits and risks associated with greater interconnection with other countries, and the proposed 'supergrid'?

 

These need to be carefully evaluated. The tentative evidence would seem to be that greater interconnection between power control areas does increase the risk of large - multi-national - blackouts[7]. There is also a problem of paying for international transmission links where the costs are socialized within average tariffs. This can either lead to incentives to oversize the grid (because the costs are shared among average transmission charges) or to undersize because merchant transmission cannot be justified. There is also an interaction between the gas and electricity markets which suggests that it might be more efficient to trade the gas rather than the electricity internationally. Therefore it may be more cost-effective at the European level to work on improving the gas market in Europe and efficiently arbitrage this, rather than trade the electricity.

 

· What challenges will higher levels of embedded and distributed generation create for Britain's electricity networks?

 

This requires distribution networks to become active rather than passive networks. Serious consideration needs to be given to network regulation which encourages local generation. Ofgem have begun thinking about this in the context of how electricity regulation can learn from telecoms[8]. The argument here is that we need to encourage more contestability in local wires, with the threat of purchase by local generators of sections of the existing networks or the creation of private (duplicate) wires and the leasing of wires on fair terms. New forms of ownership of local distribution assets, as say part of Local Authority Energy Service Companies or Customer Cooperatives might also be necessary to cope with lock-in of customers to local supply and to encourage local political support.

 

It is possible that the creation of a more active distribution network requires a significant reorganisation of the electricity sector. In particular consideration should be given to ownership unbundling distribution wire businesses from the rest of the electricity system (similar to the position of National Grid in transmission) in order to avoid incentives to discriminate in favour of own generation or supply in an active distribution system. This has occurred in New Zealand already.[9] It might also involve the creation of new kinds of licences for local electricity companies (e.g. for a local authority led ESCO in each municipal area) who would have specific responsibilities to deliver locally generated power and heat and in return receive regulatory or fiscal support/exemptions.[10]

 

An important part of the mix is customer engagement. It will be increasingly important that individual customers respond to financial incentive to economise on carbon and energy. It is also important that they embrace new technology such as smart meters and the intensive use of data that they will eventually facilitate. Thus individual consumers will need to welcome own and local generation and to voluntarily submit to demand response measures either directly of via energy service companies. This will be key to the successful uptake of much more local generation. An important part of the policy to get right will be that towards the fuel poor. Customer engagement offers the prospect of initially targeting the fuel poor for energy efficiency measures and subsidy support. This has high potential as popular policy if implemented sensitively.

 

· What are the estimated costs of upgrading our electricity networks, and how will these be met?

 

Network costs cannot be separated from power costs and must be looked at in the round. It is very important to only upgrade networks when this is necessary. If we can reduce electricity demand it may be possible to slow the rate of replacement of electricity network assets and this may be a significant saving. Regulated companies need to be given strong incentives to prolong the life of assets where there is no technical reason to replace them.

 

· How can the regulatory framework ensure adequate network investment in light of the current credit crunch and recession?

 

In my view the existing system is capable of adjusting to the credit crunch. Revenue will adjust marginally in line with falls in demand which is appropriate. The calculation of the regulatory weighted average cost of capital - WACC - will also adjust at the time the prices are reset. Regulated network companies remain relatively attractive investments to the credit market. The credit crunch will offer strong incentives to regulators and government more generally to clarify the investment regime and reassure investors that the government is committed to a stable investment environment.

 

· How can the regulatory framework encourage network operators to innovate, and what is the potential of smart grid technologies?

 

The Innovation Funding Incentive (IFI) run by Ofgem which encourages companies to spend up to 0.5% of their revenue on R&D is important. This is a good scheme because creates extra revenue for R&D expenditure and it involves an element of co-funding and competition. It is important that incentives exist to undertake larger scale trails, as the town/city level. In my view the IFI should be evaluated with a view to expanding it (say to 2% of revenue) with the money being put into a pot which not only network companies but other players (e.g. generators, suppliers and local councils) could bid to conduct large town level demonstration scheme (e.g. to promote a local smart grid / energy service company).

 

· Is there sufficient investment in R&D and innovation for transmission and distribution technologies?

 

Almost certainly there is not enough R&D being done given the scale of the future investments expected. The IFI scheme for electricity transmission and distribution currently only raises around £20m per year. This would not be sufficient to support a set of large scale demonstration projects suggested above.

 

· What can the UK learn from the experience of other countries' management of their electricity networks?

 

In England and Wales National Grid have an on-shore monopoly of new build of transmission assets and are integrated with system operation. It is not clear that this is desirable especially in a world where grid investments should compete directly with generation and where local and remote generation should also compete (and hence distribution and transmission system investments are substitutes). We should therefore consider the creation of a separate GB wide system operator operated on a not-for-profit basis (similar to the situation in US jurisdictions, Chile and Argentina etc). It would also be desirable if large new on-shore investments were made under competitive tender and decided on via a process of negotiated settlements. Serious consideration should be given to the lessons from overseas experiences of separate independent transmission operator(s) (ITO) and independent system operators (ISO). These systems can operate as well as the England and Wales system of a single independent transmission system operator (ITSO)[11].

 

The UK has a largely monochrome approach to the delivery of energy services via electricity and gas networks. Other countries have traditionally had a more diverse approach with a combination of heat networks as well as gas and electricity (e.g. Denmark, Germany etc). This has involved a significant role for district heating and increasingly own generation (e.g. Germany's support for residential solar power). In other countries also make much more use of smaller more local energy utilities and customer cooperatives which might be capable of fulfilling an important role in showcasing innovative approaches to energy service management (e.g. rural electric cooperatives in the US and local electricity distribution companies in Norway and Sweden). We in the UK need to consider whether a more localized approach is part of the solution in the future. This plays to the need to engage individuals and local communities in tackling climate change and to encourage the use of local resources as opposed to relying on big national level projects. Such a local approach - reflecting the ESCO and Micro-grids scenarios in the LENS report - would require significant regulatory support and government subsidy particularly at the beginning to trial new business models in the UK energy sector. Thus while the UK electricity market liberalization has been very successful, it is also the case that Scandinavian countries have followed a very different path at the local level and seem to have also had successful energy market liberalizations. A closer look at what lessons can be learned from these countries would seem to be appropriate.

March 2009

 

 

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[1] See Ault, G., Frame, D. and Hughes, N.(2008), Electricity Network Scenarios in Great Britain for 2050, Final Report for Ofgem's LENS project, London: Ofgem.

[2] Here we draw on Pollitt, M. (2008a), 'The Future of Electricity (and Gas) Regulation in a Low-carbon Policy World', The Energy Journal, Special Issue on 'The Future of Electricity: Papers in Honor of David Newbery', pp.63-94. and Grubb M., Jamasb, T. and Pollitt, M. (2008) (Eds.), Delivering a Low-Carbon Electricity System, Cambridge: Cambridge University Press, pp. 487-495.

 

[3] For a summary see Littlechild, S. (2008) "Some applied economics of electricity regulation." The Energy Journal, 29(S2): 43-62.

[4] MacKay, D. (2008), Sustainable Energy - Without the Hot Air, Cambridge: UIT.

 

[5] See Littlechild (2008) op cit.

[6] See Pollitt, M. (2004) "Electricity reform in Chile: lessons for developing countries." Journal of Network Industries, 5(3-4): 221-262.

[7] Yu, W. and Pollitt, M. (2009) "Does liberalisation cause more electricity blackouts? Evidence from a global study of newspaper reports." Electricity Policy Research Group Working Papers, No.EPRG0902. Cambridge: University of Cambridge.

[8] See Pollitt, M. (2009, forthcoming), Does Electricity (and Heat) Network Regulation have anything to learn from Fixed Line Telecoms Regulation?, Mimeo. Referred to in Ofgem (2009), Regulating energy networks for the future: RPI-X@20 Principles, Process and Issues, Ref. 13/09, London: Ofgem.

[9] See Nillesen, P. and Pollitt, M.G. (2008) "Ownership unbundling in electricity distribution: empirical evidence from New Zealand." Electricity Policy Research Group Working Papers, No.EPRG0820. Cambridge: University of Cambridge.

[10] For a review of existing local authority ESCOs in the UK see Kelly, S. (2008), Economic competitiveness of combined heat and power district heating networks in the UK, M.Phil.Engineering for Sustainable Development, Thesis, University of Cambridge.

 

[11] Pollitt, M. (2008b) "The arguments for and against ownership unbundling of energy transmission networks." Energy Policy, 36(2): 704-713