Select Committee on Trade and Industry Appendices to the Minutes of Evidence


Supplementary memorandum by Ofgem



  1.1  In his replies to the Trade and Industry Committee on 4 December, Callum McCarthy made reference to the fact that Ofgem is trying to "develop better locational signals to encourage the co-location, or closer co-location, of demand and generation".

  1.2  This note seeks to explain why Ofgem is trying to do this in terms of the potential benefits relating to lower:

    —  transmission and distribution losses; and

    —  transmission constraints[51].

  1.3  These effects are desirable because they should lead to lower costs for customers both directly, as a result of the costs of operating the transmission and distribution systems falling, and indirectly, since the level of network reinforcement required going forward should also be lower if new generation and demand are located near to each other.

  1.4  To understand why closer co-location could achieve these results, it is necessary to understand how losses and constraints arise. The transmission of electricity down wires results in electricity losses, some of which are proportional to the distance that the electricity has to travel from generation to demand. Thus, all other things being equal, the closer that producers are to consumers, the lower will be the overall level of transmission and distribution losses. Reducing such losses through developing better locational signals will therefore have environmental benefits, to the extent that less fossil fuel generated electricity will need to be produced, with a resultant decrease in environmental emissions.

  1.5  Transmission constraints arise when, in a particular location, the capacity of the transmission or distribution system is inadequate to deal with the electricity flows that are predicted to occur whilst maintaining the safety and security of supplies. Whilst closer co-location will not necessarily result in fewer constraints[52], it is generally the case that separating generation and demand gives rise to more potential constraints. Since constraints depend on the pattern of electricity flows and these can change over the course of a day (as a result of demand changes), by season (as result both of demand changes and the temperature dependence of equipment capabilities) and over time (as the locational pattern of generation and demand changes), it is not necessarily the case that it is economic to undertake network investment to resolve a constraint that may be intermittent or short-term in nature.

  1.6  Ofgem has been consulting on the issue of locational signals in England and Wales under the New Electricity Trading Arrangements (NETA) since 1999. As described below, we have proposed to sharpen the locational signals that generation and demand receive in relation to both transmission losses and transmission access. We believe that once the arrangements in England and Wales have been reformed, the Scottish arrangements should be made consistent with them as part of a more general reform leading to British Electricity Trading and Transmission Arrangements (BETTA). Consequently, in the rest of this note, we concentrate upon the situation in England and Wales.

  1.7  The only locational signals that generation and demand in England and Wales receive at the moment come from the Transmission Network Use of System (TNUoS) charges, which are designed to reflect the long run costs of reinforcing the system to accommodate additional generation or demand in different locations. For generators, there are 15 charging zones whilst for demand there are 12 (each one corresponds to the area of one of the 12 distribution networks). These estimates of long-run investment costs, whilst useful, are not intended to reflect the locational costs relating to transmission losses or constraints.

Transmission losses

  1.8  Under the current arrangements, there are no direct locational signals in relation to transmission and distribution losses. Thus a generator that is located far away from any demand faces the same exposure to losses as a generator that is located close to demand, and similarly in relation to remote demand.

  1.9  On the basis of demand and the plant on the system in England and Wales in 2000-01, the National Grid Company (NGC) has estimated the contribution that additional 1 MW of demand or production in various locations would make to transmission losses, ie their marginal impact. This is shown in Table 1 below, which demonstrates quite clearly the significant locational element to transmission losses.

Table 1

Generation ZoneLosses (per cent) Demand ZoneLosses (per cent)
North4.0Northern -3.5
Humberside2.3Norweb -0.6
N Yorkshire & N Lancashire2.4 Yorkshire-0.8
S Yorkshire & S Lancashire0.7 Manweb0.0
North Wales0.8East Midlands 1.3
West Midlands-1.3Midlands 2.6
Rest of Midlands & Anglia0.5 Eastern0.7
South Wales-3.0South Wales 3.5
Wiltshire-2.5Seeboard 1.6
Greater London-1.3London 2.0
Estuary0.0Southern 2.8
Inner London-1.9South Western 3.8
South Coast-2.0
SW Peninsula-6.1

  1.10  Overall, NGC considers that the introduction of locational transmission loss signals might reduce the costs of operating the system by around £3 million per annum (out of a current total losses bill of around £100 million) but this analysis ignores the impact of any changes in behaviour or siting decisions by customers. Other commentators have suggested that the benefits could be significantly higher than this.

  1.11  Ofgem has been consulting on the issue of introducing locational (zonal) loss factors NETA since December 1999 and intends to issue a further consultation early in 2002. [53]Following this, it will be for market participants to bring forward modifications to implement the necessary changes to the Balancing and Settlement Code (BSC), and other core industry documents, in order to introduce some form of zonal losses scheme.

  1.12  The Gas and Electricity Markets Authority will then decide whether the BSC should be changed in accordance with the proposed modification. In doing so it must have regard to whether the modification better facilitates the applicable BSC objectives, which are:

    —  the effective discharge by NGC of the obligations imposed upon it by its Transmission Licence;

    —  the efficient, economic and co-ordinated operation by NGC of its transmission system;

    —  promoting effective competition in the generation and supply of electricity, and (so far as consistent therewith) promoting such competition in the sale and purchase of electricity; and

    —  promoting efficiency in the implementation and administration of the balancing and settlement arrangements.

Distribution losses

  1.13  Distribution losses are much higher than transmission losses because electricity is distributed at lower voltages than it is transmitted. Typically, transmission losses are less than 2 per cent of the electricity generated whereas average distribution losses are just under 7 per cent. Generators who are connected to the transmission network do not contribute to the costs of distribution losses, which are borne by customers and by generators connected to the distribution network (embedded generators).

  1.14  There are 12 regional distribution networks in England and Wales, each of which separately calculates distribution charges (including an element for losses) subject to regulatory oversight by Ofgem in the form of periodic price controls. As Table 2 shows, there is no strong regional differentiation in the level of distribution losses but there will be locational effects within zones that are not currently captured in distribution charges. However, in most instances intra-zonal locational effects will be relatively small because the distribution system will be connected to the transmission system at several different points, effectively providing generation (electricity inputs) from a number of different sources.

Table 2

East Midlands6.1%
South Wales7.7%
South Western7.3%

  1.15  In addition to locational effects, the power factor at each connection point on a distribution system can influence the level of distribution losses. Power factors describe the size of power flows across the distribution system (measured in kVA) necessary to ensure that a customer's demands (measured in kW) are met. A customer with a poor power factor requires a larger power flow per unit of demand than a customer with a high power factor. If power factors are improved and power flows reduced then power flows and hence network losses should fall.

  1.16  Whilst several distribution networks have adopted metering that measures all components of the power supplied to their larger customers and levy explicit charges related to poor power factors, the practice is not universal. Ofgem has been consulting on whether distribution network operators have taken adequate steps to encourage the efficient use of energy, including by incentivising larger customers to improve their power factors. It must be recognised, however, that the effectiveness of any tariff structure in providing correct signals to reduce network losses will largely depend on how suppliers reflect these price signals within charges to customers.

Transmission constraints

  1.17  As for transmission losses, under the current arrangements the costs of transmission constraints are smeared across all users of the transmission system. To target the costs of transmission constraints on those who cause them, it will be necessary to reform the current transmission access arrangements.

  1.18  The costs of transmission constraints are currently relatively modest, around £40 million. However, possible developments in the pattern of European-wide electricity flows could have significant consequences for the level of constraints in England and Wales. New interconnectors from Norway and the Netherlands to the UK are being discussed that might substantially alter the pattern of flows in England and Wales. Moreover, it is also possible that flows on the French interconnector could, particularly at times of peak, reverse direction over time given the increasing age of some of the marginal French coal stations. Previous analysis has suggested that if the flows on the French interconnector were to reverse fully ie electricity was always to flow to France rather than from France, the costs of constraints could increase by as much as £100 million. Ofgem has not taken any particular view on how electricity flows will develop. Rather it is our view that the increased uncertainty associated with such developments requires efficient transmission access arrangements to be introduced to ensure that participants and NGC receive appropriate signals to respond to changing circumstances in a timely fashion.

  1.19  Whilst these European impacts cannot be addressed via the closer co-location of domestic generation and demand, other UK constraint issues, notably the likely increase in north-south constraints from the expansion of the Scottish interconnector, could be alleviated if generation and demand were incentivised to locate closer to each other.

  1.20  Ofgem has issued two consultation papers relating to the need for the reform of the transmission access regime and intends to publish another early in 2002 (covering both transmission access and losses). Thereafter, as for losses, it will be for market participants to propose amendments to the current arrangements to introduce more cost-reflective and hence locational transmission access arrangements and for the Gas and Electricity Market Authority to determine whether these amendments should be implemented.


  2.1  In his evidence to the Trade and Industry Committee on 4 December, Callum McCarthy said that "there are proposals coming forward in this country for investment on a significant scale in [electricity] storage which if that comes about will actually revolutionise the position of renewables".

  2.2  The demand for electricity fluctuates from season to season and hour by hour throughout the day. Maximum demand may last for only a few hours in a year. Plants typically have had to be built to handle peak usage requirements. Expensive plant can be under-utilised and peak demand may be covered by older plant that may be less environmentally satisfactory. Storage may be an attractive way commercially to cover peaks in demand, depending on its relative cost. In the past investment has led to the following attempts to develop cost-effective technologies to store electricity:

    —  pumped storage uses connected upper and lower water reservoirs. When electricity demand and prices are low, it is used to pump water from the lower to the upper reservoir. Electrical energy is thus converted into potential energy in the stored water. When this stored energy is required, the water is released to turn turbines to produce electricity. However, the technology has limited potential since such projects require suitable geographical conditions; also, there may be considerable environmental and amenity impact due to the reservoirs themselves. The latter is likely to result in planning consent being contentious for new schemes;

    —  batteries store electricity in the form of chemical energy. Only limited progress has been made in improving the performance of batteries so that they can store electricity in bulk. While a small number of battery energy storage plants have been built, wider application of this technology still seems some way off; and

    —  other storage technologies, using compressed air and flywheels, suffer from technical and cost drawbacks which presently hamper their commercial development.

  2.3  There is considerable interest in the investment in one potential method of electricity storage which is now taking place. Regenesys Technologies is now, in Britain and the USA, building the first "electricity warehouse" designed to operate on a utility scale. It is likely to be the largest commercial plant of its type with operation expected in spring 2002. The Regenesys system uses regenerative fuel cell technology (a fuel cell is an electrochemical energy conversion device that converts hydrogen and oxygen into electricity and heat) and delivers electricity to the network by extracting electricity from charged electrolytes in a reversible electrochemical reaction. The conversion of electrical to stored chemical energy and back again can be repeated indefinitely and fairly efficiently. This technology is currently 60-65 per cent efficient, but this is expected to improve in later plants. Bulk supplies of electrical energy can be stored for as long as necessary and released when needed. This technology has been developed by Innogy Technology Ventures Limited, a subsidiary company of Innogy plc.

  2.4  Flexible storage plants could operate alongside conventional and renewable generating plants, storing output and releasing it when needed. If they were located at key points on the supply system, they would help maintain voltage and frequency stability. With careful siting, they could cut the energy losses resulting from electricity being transmitted over long distances, and could also reduce the need for new transmission lines. As new lines are frequently contentious, this technology could be beneficial in avoiding or deferring them, by providing an alternative means of network reinforcement to meet local peak demand. Consent would of course be needed for the storage plant.

  2.5  Plants using energy storage technology can be designed to have high availability, and require relatively smaller sites than conventional power stations. Other applications for such plant include enhanced flexibility, rapid response, spinning reserve and ramping, capacity deferral, line stability and reliability, reliability for end use customers and power quality. These services could be traded commercially as distribution or transmission ancillary services, which are potentially additional benefits of storage technology.

  2.6  The electricity storage technology that has been developed may also benefit renewables, in that output from renewable sources of electricity could be harnessed more efficiently with its output being stored and released when needed, and or sold when its value is relatively high. For example, a wind farm could benefit additionally because it could overcome elements of unpredictability and intermittency by drawing on stored electricity and releasing the forecast amounts onto the system. This would help such generators reduce their imbalance charges under NETA and so could be commercially attractive to the generator. Clearly the extent to which such storage technologies are developed will depend on their commercial performance, both on a stand-alone basis and when harnessed with particular generating technologies.

  2.7  As the technology is modular with separable power and energy ratings, a design can be tailored to match the requirements for any specific point on a power network. Many renewable generators are located on the distribution networks. Having storage potential attached to such renewable generators may contribute to changing the way that distribution networks are managed. Ofgem and DTI are taking forward this work as part of the joint Distributed Generation Working Group. It is also suited to the integration of renewable generation in grid connected networks. For example, offshore wind might use storage to overcome transmission constraints.

  2.8  Generators will have to consider the costs of any storage option. For example they could consider contracting with a specialist company to provide energy storage services.

  2.9  If storage becomes commercially attractive on a sizeable scale, there should need to be fewer new power stations built to meet, securely, the peak demand for electricity. The remaining generating capacity may become capable of being operated more efficiently if its output does not need to change so much to respond to demand fluctuations.


  3.1  Ofgem has been asked to clarify its position on the minimum necessary excess of generating capacity over demand. This excess is typically referred to as the plant margin, which is calculated as the percentage by which the installed capacity on the system exceeds peak demand.

  3.2  Ofgem does not have a view on what constitutes a minimum acceptable plant margin. In an efficiently operating market, a declining plant margin should be reflected in rising prices (all other things being equal) and this should encourage the construction of new plant to the extent that the market believes that this is warranted. Where sites and financing are readily available, plant that are required to operate only infrequently to meet peak demand (such as open cycle gas turbines) can be built and commissioned within a year so a rapid response is possible if necessary. Generating units that have been mothballed can be brought back to service over a period of months whilst contracts to interrupt large demand loads can be negotiated over very short timescales.

  3.3  The plant margin in England and Wales has varied considerably over the course of the last 10 years, as shown in Figure 1. The graph shows the plant margin both on the basis of actual peak demand and on the basis of weather corrected (average cold spell[54]—ACS) peak demand. Over the past 10 years, there have been a succession of milder than normal winters and hence the actual plant margin has been consistently above the weather corrected margin.

  3.4  At privatisation, the plant margin was around 30 per cent but it dropped down to 15 per cent by 1995-96 as a result of a rapid programme of closures of oil and small coal plant. Since then, the building of new plant has led to a steady increase in the plant margin, which NGC forecasts will reach nearly 27 per cent in 2001-02.

  3.5  Since plant margins are calculated on the basis of installed capacities, they do not reflect the actual excess of generating capacity over demand that will be seen on any given day. This is because, typically, some plant will be unavailable as a result, for example, of planned maintenance or breakdowns. In addition, bottlenecks on the transmission network can on occasions prevent plant operating at their full capacity, furthering reducing the actual excess of available generation over demand.

  3.6  Under NETA, there are a number of incentives that encourage plant to strive to be available. First, if the system is tight ie the excess of available capacity over demand is low, then the prevailing prices both in the spot market and the Balancing Mechanism are likely to be high so that the plant will forgo potentially lucrative opportunities to sell its power if it is unavailable. Second, if a plant has sold a contract but is unable to deliver the power to back that contract, it will have to buy power to cover the contract. If it has to buy power at a time when the system is tight then, as just noted, it may have to pay a high price, particularly if the power has to be bought by NGC via the Balancing Mechanism. [55]In the run up to the introduction of NETA, it was noticeable that more maintenance was being undertaken than had been usual under the Pool, indicating that generators appreciated that there would be strong commercial incentives to make and keep plant available.


  4.1  It has been suggested to the Trade and Industry Committee by some witnesses that international investments by either NGC or Transco could theoretically affect their economic stability such that they could not fulfil their statutory obligations in the UK (ie they might not be able to invest at a level necessary to maintain and develop their networks).

  4.2  This note summarises the obligations on NGC and Transco to maintain such investment capability and Ofgem's role and responsibilities for enforcing these obligations.

  4.3  For a broad discussion of the possible threats to the financial position of licensed energy network operators in Great Britain that might arise from participation in wider international activities, and possible safeguards against this, it is helpful that the Monopolies and Mergers Commission's report on the PacifiCorp/The Energy Group merger reference discussed these issues at length.

  4.4  That report contained a discussion of the package of ring-fencing conditions that the then Director General of Electricity Supply had proposed should be introduced into the licence of Eastern Electricity. That package formed the basis of the standard ring-fencing conditions that are now incorporated in all British distribution, transmission and gas transportation licences, although these have subsequently been strengthened in a number of respects. OFFER consulted on a number of further modifications in 1998, and during 2000 Ofgem consulted on additional measures as part of its programme of consultation on standard licence conditions in connection with the implementation of the Utilities Act 2000. At present the ring-fencing conditions have operational effect only in the licences of the ex-PES distribution companies, all transmission licensees, and Transco.

  4.5  By way of summary, the financial ring-fencing conditions require a licensee to conduct its affairs at all times so as to ensure that it has available to it sufficient resources of all kinds (expressly including financial resources and facilities) on such terms and with such rights as will secure that it is able to discharge its licence and statutory obligations and finance the carrying on of its licensed activities.

  4.6  This fundamental duty is supported by a number of other obligations and restrictions on licensees (as opposed to other companies in the same corporate group), as follows:

    —  the licensee may not conduct any other activity nor carry on any other business apart from its Distribution, Transmission or Transportation business (as the case may be). So-called de minimis businesses in aggregate may not account for more than 2.5 per cent of either turnover or shareholders' funds;

    —  the licensee may not dispose of nor relinquish operational control over any asset forming part of its distribution/transmission/transportation (as the case may be) system without the consent of the Authority (which, inter alia, prevents any security interest being created in any such asset);

    —  the licensee may not acquire nor hold any investment of any kind other than in affiliates that carry on business solely for a purpose of the licensed business or in the ordinary and proper course of its treasury operations (provided it has in place a system of internal controls meeting or exceeding the requirements of the Committee on Corporate Governance);

    —  the licensee must use all reasonable endeavours to maintain at all times an investment grade corporate credit rating;

    —  the licensee may not incur any indebtedness, nor give any security or guarantee except for a purpose of its licensed business, on an arm's length basis and on normal commercial terms;

    —  the licensee may not make any transfer of any sum or sums, asset, right or benefit to any affiliate except for certain specified purposes subject to stipulated conditions. In particular, unless the transfer is for a consideration at least equal to the value of the asset transferred and which is received in full no later than the time of the transfer, the transferee must have and agree at all relevant times to maintain an investment grade corporate credit rating;

    —  the licensee may not incur any cross-default obligation whereby its liability to pay or repay any sum arises, is increased or accelerated by reason of the default of any other person (other than a person which is a majority-owned and controlled subsidiary carrying on business solely for a purpose of the licensed business);

    —  the licensee must obtain legally enforceable undertakings from each person that it is an ultimate controller (as defined) of the licensee that it will (a) refrain, and procure that each other person controlled by it refrains, from any action likely to cause a breach of the licensee's licence, and (b) that it will provide, and procure that each other person controlled by it provides, any information the licensee may reasonably request in order to comply with a direction of the Authority;

    —  the licensee must comply with any direction of the Authority to enforce any such undertaking and, for so long as any such undertaking as should be in place is not in place, or is in breach, the licensee may not enter into any arrangement with any affiliate; and

    —  the licensee is required to certify annually to the Authority that it has adequate financial resources and facilities to enable it to finance the conduct of its licensed business for the ensuing 12 months, and, before declaring or paying any dividend or other distribution, to certify to the Authority that (a) it is in compliance in all material respects with the ring-fencing conditions (as described above), and (b) that the payment of such dividend or other distribution will not cause it to breach any of these conditions then or in the future, whether alone or in conjunction with any other foreseeable event or circumstance.

  4.7  Taken together, Ofgem considers that this package provides adequate safeguards to the ability of the licensee to finance the carrying on of its licensed business and the discharge of its obligations, including in particular the obligation to develop and maintain an efficient, economic and co-ordinated distribution/transmission/transportation (as the case may be) system. The MMC report referred to above concurred in this view.

  4.8  It is worth noting that appointments under the Water Industry Acts contain similar ring-fencing conditions. As a result of these, the credit rating agencies have maintained the rating of Wessex Water notwithstanding the collapse of the Enron group which owns Wessex. Consequently, Wessex has not experienced difficulty, even of a temporary nature, in funding itself. This suggests that the financial ring-fencing conditions provide adequate safeguards.

51   Distribution networks tend not to experience the sort of capacity constraints that occur on the transmission network. Hence, the cost of distribution constraints and the scope for reducing them are limited and are not discussed in this note. Back

52   If a power station is connected to a demand-site via a transmission line whose capacity is inadequate to cover peak flows, constraints will arise however short the line may be. Back

53   As discussed below, this consultation process has covered transmission access arrangements as well as transmission losses. Back

54   ACS weather is that which is experienced one in eight years. Back

55   If a plant fails after the bilateral market has closed (currently this occurs three-and-a-half hours before the start of a trading period), it cannot replace the power through bilateral trading but has to rely upon NGC, as system operator, to do so and will then have to pay the system buy price for that power. Back

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