A DISTRIBUTION NETWORK REVIEW

ETSU K/EL/00188/REP

Contractor P B Power

Merz & McLellan Division

PREPARED BY R J Fairbairn D Maunder P Kenyon

The work described in this report was carried out under contract as part of the New and Renewable Energy Programme, managed by the Energy Technology Support Unit (ETSU) on behalf of the Department of Trade and Industry. The views and judgements expressed in this report are those of the contractor and do not necessarily reflect those of ETSU or the Department of Trade and Industry.__________

First published 1999 © Crown copyright 1999

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1. EXECUTIVE SUMMARY.........................................................................................................................1.1

2. INTRODUCTION.......................................................................................................................................2.1

3. BACKGROUND.........................................................................................................................................3.1

3.1 Description of the existing electricity supply system in England, Scotland and Wales ...3.13.2 Summary of PES Licence conditions relating to the connection of embedded generation3.53.3 Summary of conditions required to be met by an embedded generator.................................3.103.4 The effect of the Review of Electricity Trading Arrangements (RETA)..............................3.11

4. THE ABILITY OF THE UK DISTRIBUTION NETWORKS TO ACCEPT EMBEDDEDGENERATION...................................................................................................................................................4.1

4.1 The ability of distribution systems to accept embedded generation........................................ 4.14.2 Northern Scotland - Scottish and Southern Energy...................................................................4.44.3 Central and Southern Scotland - Scottish Power...................................................................... 4.124.4 North East England - Northern Electric...................................................................................... 4.164.5 North West England - Norweb...........................................................................................................4.204.6 Merseyside and North Wales - Manweb..........................................................................................4.244.7 Yorkshire and Humberside - Yorkshire Electricity.................................................................... 4.294.8 West Midlands - Midlands Electricity............................................................................................4.334.9 East Midlands - East Midlands Electricity................................................................................... 4.364.10 Norfolk and East Anglia - Eastern Electricity............................................................................4.404.11 Central London - London Electricity.............................................................................................4.434.12 South East England - SEEBOARD..................................................................................................... 4.454.13 Southern England - Southern Electric...........................................................................................4.494.14 South Wales - SWALEC.........................................................................................................................4.514.15 South West England - SWEB............................................................................................................... 4.55

5. TECHNICAL BENEFITS/DRAWBACKS ARISING FROM EMBEDDED GENERATION...........5.1

5.1 Utilisation of distribution network assets...................................................................................... 5.15.2 Distribution System Losses and Overall System Efficiency....................................................... 5.25.3 Security and quality of supply............................................................................................................. 5.55.4 Need for distribution reinforcement................................................................................................. 5.75.5 Avoidance or deferment of distribution reinforcement..............................................................5.85.6 System control, load balance and safety........................................................................................5.85.7 Implications forNGC............................................................................................................................... 5.9

6. POTENTIAL FOR UPTAKE OF EMBEDDED GENERATION TECHNOLOGIES........................6.1

6.1 The Projected Near-term Uptake of Renewable Energy Projects in England, Scotland and Wales6.16.2 The Projected Near-term Uptake of Embedded Fossil-fuelled Projects in England

Scotland and Wales...........................................................................................................................................6.14

7. COMPARISON OF DISTRIBUTION NETWORK CAPACITY WITH POTENTIAL UPTAKE ...7.1

8. POSSIBLE SOLUTIONS TO OVERCOME OBSTACLES.................................................................. 8.1

8.1 Voltage regulation 8.1

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8.2 Thermal Loading.......................................................................................................................................8.38.3 FAULT LEVELS................................................................................................................................................ 8.48.4 OTHER ISSUES................................................................................................................................................ 8.5

9. CONCLUSIONS AND RECOMMENDATIONS.................................................................................. 9.1

9.1 Existing distribution systems.............................................................................................................. 9.19.2 Existing levels of embedded generation............................................................................................9.19.3 Potential benefits/drawbacks for the connection of embedded generation......................... 9.29.4 Experience of PES Companies dealing with embedded generation.............................................9.49.5 The effect of the Review of Electricity Trading Arrangements (RETA)................................9.49.6 Potential growth of embedded generation...................................................................................... 9.59.7 Fossil Fuelled Projects...........................................................................................................................9.69.8 Comparison of network capacity with Potential uptake of embedded generation...............9.69.9 Potential Solutions to difficulties experienced with Embedded generation......................... 9.79.10 Recommendations......................................................................................................................................9.9

Appendix A Scope of work

Appendix B Assessment of capability of PES networks to accept new embedded generation

Appendix C Questionnaire responses from Industry Stakeholders

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1. EXECUTIVE SUMMARY

This report covers the work undertaken by PB Power, Merz and McLellan Division, on behalf of ETSU, as part of the United Kingdom’s Department of Trade and Industry (DTI) New and Renewable Energy Programme. The objective of the study is to review the distribution network in England, Wales and Scotland to examine its ability now and in the near future to accommodate more embedded generation, taking account of both renewable and conventional types of generation. For the basis of these studies we have considered generators with a registered capacity of less than 100 MW.

The studies described in this report were performed in late 1998 and early 1999 and they involved soliciting the views of numerous organisations, including the 14 Public Electricity Supply companies, the Electricity Regulator (OFFER), key policy makers and industry stakeholders.

As a background to the studies we have included a general description of the existing transmission and distribution systems in the United Kingdom. This description includes a brief history of how the networks were developed from discrete, isolated power systems with localised generators that served a number of specific consumers, to an interconnected network that enabled generation to supply demands in other parts of the country. As part of this background information we include a summary of the conditions stipulated in the Public Electricity Supply licences granted under the Electricity Act 1989 that are relevant to the developers of embedded generation schemes. We also include a summary of the agreements and consents that an embedded generator must obtain in order to connect to, and operate on, a distribution system. This background information is included in Section 3 of this report where we also include a brief description and commentary on the Review of Electricity Trading Arrangements that are presently being performed by OFFER.

In Section 4 we present the results of our discussions with the Public Electricity Supply companies together with some analysis based on these discussions. The aim of this analysis is to identify on a regional basis the existing levels of embedded generation, the capacity for new embedded generation to be connected and the factors that impose limits to the connection of new embedded generation. In this section we also include responses from the Public Electricity Supply companies regarding their experiences of operating distribution systems with embedded generation connected. Table 1.1 below summarises the existing level of generation that is presently thought to be embedded within each of the PES companies distribution systems.

The operational experience advised by the PES companies is considered in more detail in Section 5 of this report, where we attempt to identify the technical and non-technical benefits and drawbacks that may accrue from the presence of embedded generation on a distribution network. We have performed some simplified analysis based on our understanding of the different types of typical distribution networks to compare the responses obtained from the PESs and common beliefs regarding embedded generation with the performance of idealised models. Our analysis indicates that an embedded generator of a modest capacity will tend to reduce distribution system losses, both in terms of peak power losses and annual energy losses. However, such a generator would generally be rated to meet the minimum demand of other consumers that are connected to the same part of the distribution system. In practice the capacity of generators tend to be maximised for economic reasons and are rated to meet the capability of the system to accept the generation, rather than to meet local demand.In such circumstances, depending on the capacity of the generator and the nature of the

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variations in local demand, the generator will tend to increase losses compared with the case where the generator is matched to minimum local demand. In the extreme it may be expected that both peak power losses and the overall annual energy losses could increase above existing levels. This analysis supports the operational experience related by several PES companies. Other considerations include the increase in administration effort required for the PES to operate their system with embedded generation in service, increased load forecasting uncertainties and increased numbers of nuisance trips that may affect quality of supply issues.

Table 1.1 Existing levels of embedded generation by PES company

PES Approximate level of existing embedded generation (MW)

Eastern 493East Midlands Electricity 748London Electricity 268MANWEB 712Midlands Electricity 224Northern Electric 266NORWEB 986SEEBOARD 250Southern Electric 482SWALEC 342SWEB 145Yorkshire Electricity 650Scottish Power 522Scottish Hydro-electric 1251.6Total 7339.6

The connection of embedded generation should, in theory, allow distribution companies to defer system reinforcement and allow the generation output to improve the security of supply to their customers. However, the theoretical benefits can only be realised in practice if there are suitable commercial agreements in place to ensure that the PES company can meet its obligations under the terms of its PES licence. Concerns about the availability of embedded generation and the reluctance of generators to offer a firm capacity that the PES can rely upon if required has tended to prevent the full theoretical benefits that could arise from embedded generation being realised in practice. The PES companies are obliged under their PES Licences to meet minimum security of supply conditions and as such there may be a disincentive to defer distribution system reinforcement if they can not rely on the availability of the generation when required. It is therefore likely that until there are strong commercial incentives for either developers of embedded generation projects to offer a firm generation capacity to PES companies, or for the PES to defer system reinforcement, that embedded generation will not be preferred to system reinforcement.

We have assessed the potential uptake of embedded generation in the next 5 years by polling the opinions of key policy makers and industry stakeholders. Based on our investigations we have derived estimates for the potential uptake of renewable energy, CHP and fossil fuel embedded generation schemes.

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The uptake of renewable energy projects in England, Scotland and Wales in the next five years is expected to be dominated by the contracted NFFO and SRO projects, although not all of these projects are expected to be constructed. We would, however, expect there to be some limited uptake of renewable energy projects outside of the NFFO/SRO mechanism, dominated by wind energy, some landfill gas, and with perhaps a very few municipal and/or industrial waste projects

In total we would expect that an estimated 1.8 GW of installed capacity of renewable energy projects would be built within the next five years. It is anticipated that there will be a considerable spread of capacities distributed amongst the various PES regions. About half of the PES regions are expected to have an above average capacity. The five PES regions in which the highest capacities are to be expected are Eastern, Norweb, Scottish Power, Scottish Hydro-Electric and Northern Electric. A total installed capacity for these five regions is about 1.1 GW. The main obstacles to the uptake of non­wind renewable energy projects are the availability and cost of the fuel supply, the uncertainty associated with obtaining planing consents and the problems with raising private venture capital for such projects. The NFFO and SRO initiatives are having a substantial impact on the levels of uptake of renewable energy projects and the continuance of these initiatives will obviously be expected to maintain the stimulus required to achieve a considerable penetration of renewable projects.

Predicting the near-term uptake of fossil-fuelled embedded generation plant (both CHP and non-CHP) in England, Scotland and Wales is extremely difficult, particularly at this time of substantial uncertainty and change in the Electricity Supply Industry. Nevertheless, our investigations suggest that between 1,500 and 2,750 MWe of fossil-fuelled embedded generation plant could be developed in the next five years.

Should there be strong government policy in the form of inducements or other short term measures, developers may find more projects become viable. It should be noted that there would be an 18 months to 2 year lead time to develop, engineer and construct such plants which rules out significant increases in the short term. This will require an even greater rate of take up in year 2001 and beyond to meet the Government’s 2010 objectives.

Whatever the rate of development, we expect that most of this capacity will be in the form of gas fired CHP plant with power export. We do not anticipate significant growth in District Heating in cities, based on CHP and power export. Furthermore, most of these CHP projects will be developed in the traditional industrial areas England, Scotland and Wales. It is in these regions that the impact on the local distribution systems will be highest.

Table 1.2 compares our predicted uptake of embedded generation with our expectation of what generation could be accepted by the PES networks. It is important to recognise that our expectation of the capacity that could be connected to the PES networks is an indication of the maximum total capacity from a large number of small capacity generators connected at suitable locations on the distribution systems. The best locations to connect embedded generation are generally close to primary substations at 11 kV, close to 33 kV bulk supply points or at 132 kV. The information in this report should not be interpreted as meaning that a particular PES network should be able to accept a small number of large capacity generation schemes with a total capacity equal to that indicated in Table 1.2.

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Table 1.2 Comparison of network capability to accept new generation with potential uptake over the next 5 years

Likely uptake ofPES Region Indicative renewable CHP non-CHP Total generation

network energy Capacity capacity capacitycapacity MW (MWe) (MWe) MWe

Eastern 910 264 10-150 3-40 277-454East Midlands Electricity 920 82 10-100 5-40 97-222London Electricity 390 23 10-100 5-100 38-223MANWEB 460 153 35-400 2-30 190-583Midlands Electricity 330 43 25-300 5-40 73-383Northern Electric 250 174 25-100 2-30 201-304NORWEB 620 275 10-300 2-40 287-615SEEBOARD 710 75 25-100 25-50 125-225Southern Electric 1270 61 10-100 25-100 96-261SWALEC 210 110 10-400 10-20 130-530SWEB 430 63 20-50 10-40 93-153Yorkshire Electricity 650 143 35-200 2-40 180-383Scottish Powerf 810* 217 35-200 2-40 254-457Scottish Hydro-electricf 110* 193 5-50 2-10 200-253

f These indicative capacities assume that there will be no transmission constraints imposed by the capacity of the Scotland-

England interconnector. In practice it is possible that access to the interconnector may limit the capacity of new generation that

can be connected in Scotland

* This includes the capacity of contracted SRO generators that have not already connected

We have identified a number of possible solutions to difficulties that limit the opportunities for connecting embedded generation. The major difficulties that can be presented to the connection of embedded generation are normally those related to voltage regulation, thermal loading and fault levels. The solutions may be found through technical solutions, commercial solutions and regulatory solutions. It is not intended that the order in which they are listed signifies any sense of importance or priority, which will need to be determined from further analysis. The technical solutions may include the following:

• Impose limits on generator operating power factors• Install reactive power compensation equipment• Reinforce existing circuits back to source substation• Make direct connection to source substation• Use power electronic interface to accurately control generator output to control voltage at

point of common coupling within specified range• Connect to a higher voltage system• Design connection and generator to maximise the impedance between the generator and

the PES system, minimising fault contribution.• Reconfigure the existing PES network to reduce the fault contribution from the rest of the

system.

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• increase the network short-circuit rating, by replacing switchgear etc.• Use a direct current link between the generator and the PES system to effectively eliminate

a fault current contribution from the generator.

commercial solutions may include the following:-• Restrict periods of the year when the generator can operate• Allow generator to indemnify PES against any claims or losses arising from voltage levels

outside permitted range

and regulatory solutions may include• Allow PES to schedule generation and allow NFFO/SRO generation to be constrained, as

appropriate to the local network• Allow principals within Distribution Price Control to implement appropriate technical

solutions without penalty• Examine the existing arrangements to minimise any single generator developers exposure

to system reinforcement costs.

In order to encourage increased levels of penetration of embedded generation that will be required to reach the Government’s targets for electricity production from renewable and energy efficient sources we make to the following recommendations;

• Formally separate the supply and Distribution businesses of PES companies.• Enable PES companies to charge for the transport or electricity from a generation site in a similar

way to how it charges for the transport of electricity to demand customers.• Develop commercial measures that encourage PES companies to make the best use of embedded

generation on their system.• Increase the incentives to PES companies to reduce distribution loss levels.• Review and update where appropriate Engineering Recommendation P2/5• Replace the “must take” nature of future NFFO and SRO orders (or their equivalent) with a more

flexible obligation that allows generation to be constrained under extreme system conditions• Review the requirements of G59 and in particular encourage both PES companies and developers

to consider alternatives to Rate of Change of Frequency relays for loss of mains protection.• Allow PES companies to install higher fault rating equipment when upgrading their system

Although many of the PES companies felt that embedded generators contributed very little to the performance of the distribution system whilst taking an inordinate share of engineering and administrative resources, this has not appeared to adversely affect the service they offer to potential developers. The growth of embedded generation is being managed competently by the PES companies and the development of procedures to deal with connection applications and general enquiries indicate the generally co-operative attitude that exists within the distribution companies.

In summary our investigations have indicated that there is approximately 5.5 GW of embedded generation connected to the distribution networks in England and Wales and 1.8 GW connected in Scotland. We estimate that there is the potential for between 6.4 and 9.6 GW of additional generation capacity to be connected in England and Wales and between 0.9 and 1.6 GW in Scotland without significant reinforcement to the existing systems.

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2. INTRODUCTION

This report covers the work undertaken by PB Power, Merz and McLellan Division (M&M), on behalf of ETSU as part of the United Kingdom’s Department of Trade and Industry (DTI) New and Renewable Energy Programme. The overall aim of this report is to review the distribution network in England, Wales and Scotland to examine its ability now and in the near future to accommodate more embedded generation, taking account of both renewable and conventional types of generation. However, for the basis of these studies we have considered generators with a registered capacity of less than 100 MW.

This draft report has been prepared to allow comments from ETSU and other parties that have contributed to the studies presented prior to formal submission to the DTI which is expected to lead to public circulation. Since the final report will be available in the public domain, it is the intention that this draft report will enable those organisations referred to in this report to verify the information contained and the opinions expressed.

The studies described in this report were performed by M&M during the later months of 1998 and early 1999. The studies required that the information be obtained from numerous organisations including the 14 Public Electricity Supply Companies (PESs), the National Grid Company (NGC), key policy makers and industry stakeholders. We used telephone conversations, questionnaires and face to face meetings in order to elicit the appropriate information from the appropriate organisation. The scope of the studies is included as Appendix A of this report.

In Section 3 we include background information to provide the reader with a description of the existing transmission and distribution network in the UK including a commentary on regional variations. As part of this background information we have included a summary of the PES licence conditions that relate directly to the connection of embedded generation, as these are inevitably crucial to the analysis of the ability of the distribution systems to accept increased levels of embedded generation.

In Section 4 we assess the ability of the UK distribution networks to accept embedded generation by considering, on a regional basis, the existing levels of embedded generation, the capacity for more embedded generation, network planning strategies and the factors which impose a limit to the connection of new embedded generation. This information is based on the results of our discussions with the PES companies.

The technical benefits and the drawbacks that may arise from the connection of embedded generation are considered in more detail in Section 5. In that section we have combined the experiences reported by the PES companies together with our own analysis on issues such as asset utilisation, power losses, security of supply, system reinforcement and protection.

In Section 6 we present the results of our literature search and contacts with industry on the potential for uptake of embedded generation schemes, including a regional assessment of the potential growth.

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The results of Section 4 and Section 6 are used to compare the industry prospects for the potential of embedded generation with the capability of the distribution network to accept such levels of generation, and this comparison is presented in Section 7. This comparison shows the overall and regional shortfall in network capacity and identifies the causes of such shortfalls.

We have suggested, in Section 8 of this report, a number of possible solutions to the major technical barriers which limit the connection of embedded generation, including some suggested alternative regulatory and commercial methods to overcoming the identified shortfalls.

The conclusions of the study and our recommendations to enhance the penetration of embedded generation into the UK’s electricity market are presented in Section 9.

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3. BACKGROUND

In this section we provide some background information relating to the design and operation of the transmission and distribution systems in England, Scotland and Wales, and the factors that may affect the connection of new embedded generation. The obligations placed on the PES companies by their PES licence and the Distribution Code relating to embedded generation are outlined and the legal and contractual requirements for an embedded generator are summarised. We have also included a discussion on how the present debate on the review of electricity trading arrangements could affect the operation of embedded generators, both from a PES perspective and that of the generator.

3.1 Description of the existing electricity supply system in England, Scotland and Wales

3.1.1 General descriptionThe development of the national electricity supply networkThe electricity supply network in England, Scotland and Wales is an interconnected system which connects generators of electricity that are distributed throughout the country to consumers that may be located in another part of the country. The system has been developed to ensure that electricity is transported in a secure and efficient manner. When the electricity supply industry was first established it comprised a number of separate power systems with small generating stations located close to customers located in major cities. These discrete power systems generated and distributed power at a variety of voltages and frequencies and in some areas electricity was generated and distributed at direct current. As the use of electricity increased it was recognised that there would be benefits in connecting power stations together to share the resource between neighbouring networks and eventually, due to the development of the transformer, this became a practical possibility. Following the experience of the first World War an act of parliament was passed in 1926 to improve the security of electricity supply by the construction of a high voltage transmission network to connect the best 500 power stations together to form an integrated grid. In 1948, nationalisation set up organisations to supply electricity in the UK, the generation boards were responsible for the generation and transmission of power, the area boards responsible for the distribution of the electricity to the end user.

The development of a national transmission system enabled larger, more efficient power stations to be constructed and electricity to be taken to major cities and towns in the UK and the subsequent increases in operating voltage of the transmission system to 275 kV and 400 kV enabled more power to transferred around the country. The split in the responsibilities of the organisations and the economies of scale obtained when constructing large power stations meant that when distribution systems were designed there was little thought given to these lower voltage systems accepting generation. This now represents a fundamental difficulty to the development of embedded generation schemes.

The present situationIn England and Wales the transmission system comprises an interconnected 400 kV and 275 kV system that is owned and operated by the National Grid Company (NGC), with circuits operating at 132 kV and below forming the distribution network being owned and operated by Regional Electricity Companies. In Scotland, 132 kV circuits are considered as part of the transmission system network and systems that have a nominal voltage of less than 132 kV are used for distribution.

The transmission system comprises a network of three phase circuits employing overhead lines that are supported by lattice steel towers and sections of underground cable. The very high cost of underground

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400 kV and 275 kV cable relative to that of an equivalent overhead line has resulted in the majority of the transmission system being constructed using overhead lines. The transmission system also has interconnections between England and Scotland, which at the moment allows 1200 MW to be transferred, and interconnections to France through the submarine cable connection that presently allows the transfer of 2200 MW between England and France. Both the England-Scotland and England- France interconnections are designed to facilitate the two-way transfer of power, but at present the commercial conditions are such that power is predominately imported by England.

In Scotland an extensive 132 kV system is used to interconnect load centres that are supplied by 33 kV or 11 kV systems that often contain embedded generators, normally relatively small hydro generators.In northern Scotland the 132 kV system operates in parallel to their 275 kV system as an integral part of Hydro-Electric’s transmission system. In Southern Scotland, Scottish Power’s territory, the 132 kV system extends from Glasgow down the west coast to the Solway Firth, across to Chapel Cross power station, through the borders to Galashiels and Berwick and back north to Edinburgh. Scottish Power have plans to reinforce this network by overlaying large sections of the existing system with 275 kV circuits.

In England and Wales the 132 kV systems that are owned and operated by the twelve PES companies are used primarily for distribution, being overlaid by the higher voltage transmission systems. The 132 kV systems are connected to the transmission system through transformers at substations that are known as Grid Supply Points (GSPs). At the 132 kV side of these GSPs some assets may be owned by NGC and others by PES companies. Assets such as 132 kV connected reactive compensation equipment is normally owned and operated by NGC. A GSP may be used to supply more than one PES company and so there may be assets belonging to different PESs at any given GSP.

There are number of possible network designs that may be used to meet the requirements of the system planning standards, but generally most of the distribution networks have been developed in a similar manner due to the collaborated nature of the industry prior to privatisation. From a GSP the 132 kV networks supply large industrial customers (tariff customers) and other substations which transform the voltage down, normally to 33 kV or sometimes to 66 kV or 11 kV. These substations are known as Bulk Supply Points (BSPs). The 132 kV distribution system (or sub-transmission system as it is sometimes referred to in England and Wales) consists of a network of three phase circuits that are constructed using a mixture of overhead lines, usually supported by lattice steel towers or in some cases by poles, and underground cables. The high cost of installing 132 kV underground cable circuits relative to that of equivalent 132 kV overhead lines has resulted in overhead lines being the preferred construction method wherever possible, although present public opposition to the visual impact of new lines and a desire to improve the quality of supply may result in more cable circuits being installed.

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From BSPs power is distributed to medium sized industrial users as well as substations closer to load centres where the voltage is transformed down to 11 kV. These substations are commonly known as primary substations. The nature of the connection between a bulk supply point and a primary substation depends upon both the requirements of the load at the primary substation and the location of the substation. In urban areas it is more likely that the circuits feeding the primary substation will use underground cables due to their short lengths and local planning requirements. In general, primary substations have a pair of transformers that operate in parallel, each capable of meeting the demand, to afford a firm 11 kV supply.

In rural areas the feeders from a primary substation are often arranged so that many 11/0.415 kV secondary substations are supplied using overhead lines in an open ring configuration. The two sections of these rings may be supplied from different primary substations therefore allowing the system to be re-supplied in the event of a fault on the normal supply circuit. In a rural area, a secondary substation often consists of a pole mounted transformer, typically rated between 5 kVA and 250 kVA, which in some cases is a single phase transformer that supplies only one or two dwellings.

Circuits from primary substations in a urban areas predominantly use 11 kV cables to supply typically up to ten 500 kVA secondary substations on each of between four and eight 11 kV feeders. Many small industrial and commercial users take their supply at 11 kV from the primary substation, or at 6.6 kV through a step-down transformer. There are usually provisions to interconnect feeders from a primary substation to allow for re-supplying in the event of a fault to a section of 11 kV cable. An alternative supply option is for 11 kV feeders to be operated in parallel, or for an interleaved or blocked secondary network where the 11 kV cables to secondary substations (or blocks of secondary substations) are routed so that neighbouring substations (or blocks of secondary substations) are supplied from different feeders with an interconnection between the neighbouring substations (or blocks). With the installation of appropriate protection facilities then, in the event of a fault occurring on the supply to a substation or block, the faulted section of cable can be isolated and the interconnection used to restore the supply.

3.1.2 Regional Variations in System DesignThere are a number of regional variations to the general arrangement of the electrical transmission and distribution systems in England and Wales as described above. In some areas there are a number of systems that operate at voltages of 66 kV and 20/22 kV. The regions with a significant number of systems at 66 kV and 22 kV are in the North East, South Wales, Yorkshire and large conurbations such as London. There are a small number of 66 kV substations in other board areas which tend to be dedicated supplies in order to supply specific customers, or are on the sites of old power stations. Two PES companies, Manweb and London Electricity, operate their distribution systems in a different way to the other 12 companies in that the systems are designed as interconnected or mesh networks. This network configuration enables the PES to offer an improved security of supply to their customers but may result in higher system fault levels, which may limit the scope for the connection of new embedded generation. A further description of the distribution networks in each PES region with some key statistics are presented in Section 4 of this report.

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3.1.3 Description of the operation of the England-Scotland InterconnectorThe interconnector between England and Scotland consists of six transmission circuits that connect Scottish Power’s and NGC’s systems. The interconnector comprises the following

• a 275 kV and a 400 kV transmission circuit between Scottish Power’s transmission substation at Strathaven in Lanarkshire and NGC’s transmission substation at Harker, Cumbria.

• a 275 kV transmission circuit between Scottish Power’s transmission substation at Cockenzie in East Lothian and NGC’s Stella West substation in Newcastle.

• a 400 kV transmission circuit between Scottish Power’s transmission substation at Torness East Lothian and NGC’s Stella West substation, and

• two 132 kV transmission circuits between Scottish Power’s transmission substations at Chapel Cross and Galashiels in the Borders and NGC’s transmission substation at Harker.

The capacity of the interconnector is calculated under procedures laid down in the British Grid Systems Agreement (BGSA) and is based, in general terms, on the maximum sustainable power transfer assuming a simultaneous outage of any two Interconnector circuits. The capacity of the interconnector is determined on a daily basis by considering a range of factors that include:

- The configuration and operating characteristics of generating sets that are operating in Scotland and in England and Wales at the time.

- Outages on the Interconnector circuits, either planned of due to faults.- Outages on the Scottish and NGC transmission circuits.- Transient stability, thermal capacity and voltage constraints on the Scottish and NGC transmission systems.

At present there are transmission constraints that limit the power transfer capability of the interconnector below its delivery capability. The present nominal capacity of 1600 MW can not be fully utilised until NGC have completed system reinforcements in northern England (principally the Second Yorkshire Line). The capability of the interconnector is determined on a daily basis and varies between 850 MW and 1800 MW, with an annual average about 1200 MW.

The Scottish Companies Transmission Businesses produce an annual Interconnector Capacity Statement that is approved by the Director General for Electricity Supply, which indicates the likely capacity and utilisation of the interconnector for the year. They also produce an Access and Allocation Code that specifies the procedure for new applicants who wish to utilise some of the capacity. The capacity available to the two Scottish Transmission businesses is specified in the Scottish Interconnector Agreement. Scottish and Southern Energy’s share is 46% of the pre-upgrade capacity (850 MW) plus 25% of the upgrade capacity. Scottish Power’s share is similarly 54% of the pre-upgrade capacity plus 75% of the upgrade capacity. At present there are three users of the interconnector capacity, Scottish Power’s Generation Business, Scottish and Southern Energy’s Generation Business, and BNFL’s Chapelcross Power Station.

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The present entitlement of the two transmission businesses based on annual average capacity of 1200 MW are:

Scottish and Southern Energy 46% of 850 + 25% of 350 = 478 MW = 40%

Scottish Power 54% of 850 + 75% of 350 = 722 MW = 60%

A recent OFFER determination on access to the interconnector required Scottish Power to offer capacity to BNFL (Chapelcross) from 1 January 1999 to 31 March 2002. The recent dispute over access to the interconnector has raised a number of matters that may lead to changes in its ownership and operation. In the recent determination on access to the Interconnector several parties expressed the view that the interconnector should be owned and operated by a third party, perhaps NGC. OFFER agreed with this view and it is possible that this could be included in the changes to the electricity market that are presently under consideration.

The capacity of the interconnection and access to use this capacity is thought to be a key consideration in the development of new generation in Scotland.

3.2 Summary of PES Licence conditions relating to the connection of embedded generation

The Distribution Code enables the PES to comply with its obligations under its PES Licence and the Grid Code. The Grid and Distribution Codes are given legal authority by the provision of licences under the Electricity Supply Act 1989 and the Distribution Code is incorporated as a term in every agreement for connection to or for the use of the PES distribution system. It is therefore important that the developers and operators of embedded generators are familiar with its requirements and apply them. A summary of the licence conditions that the PES must satisfy, which are of relevance to potential developers are as follows,

• To prepare and keep in force a code that defines the planning and operating procedures that permit the equitable day-to-day management of the PES distribution network. (Licence Condition 11 (LC11))

• To facilitate competition in supply and generation, and to provide information of their system capability on request. (LC11 and distribution code section Distribution Planning Code Sections 3 and 8.1)

• To purchase electricity at the best price reasonably obtainable, having regard to the sources available. (LC5)

• To plan and develop their distribution system in accordance with a standard of security of supply not less than that specified in Engineering Recommendation P2/5. (LC9)

• To adopt a trading code to ensure equitable energy trading practice between generation licence holders. Scottish PES companies only)

• To be transparent in the charges for standby and top-up supplies or sale of electricity, use of system and connection to the system. (LC8)

• To make an offer for a connection to and use of the distribution system (LC8b)

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• To offer standard terms of connection. (LC8c)

• To ensure commercial confidentiality of the information provided by the potential users of the system (LC12).

• To comply with the Grid Code. (LC13)

The terms of the PES licence contain a number of principles that may be of interest to the developers of embedded generation projects. Item 5 under LC8c, for example, states that when determining an appropriate proportion of costs directly or indirectly incurred in carrying out works for a connection the PES should have due regard to:

a) the benefit (if any) to be obtained or likely to be obtained by the PES or any other person as a result of carrying out such works;

b) the ability or likely future ability of the PES to recoup a proportion of such costs from third parties; andc) the principles that (for the connection of a demand customer specifically)

i) no charge will normally be made for reinforcement of the existing distribution system if the new or increased load does not exceed 25 per cent of the existing effective capacity at the relevant points on the system; and

ii) charges will not generally take into account system reinforcement carried out at more than one voltage level above the voltage of connection

Although many of the principles described in the PES licence relate to the connection of demand customers a developer may be able to argue successfully that similar principles should also be used in the consideration of a generation connection. It should be noted, however, that we are not aware of these principals being tested in practice for a generation project.

The technical criteria that may be used to assess the impact of a generator on a PES distribution system, as defined in the Distribution Code, can be summarised as follows:­

- Voltage Variations- Short circuit contribution- Conductor thermal loading- Voltage waveform quality- Voltage fluctuations (i.e. flicker)- System protection- Security of supply

3.2.1 Requirements for security of supplyThe PES licence makes specific reference to security of supply and requires that the PES plans, designs and operates its system to a standard of security that is not less than that specified in Engineering Recommendation P2/5 (1978). This document was produced in the pre-privatisation days when generation was generally controlled by central despatch. P2/5 allows the contribution of generation to the security of supply to be included in the system design, but in the present commercial market, where generators of a certain rating and export capacity are able to operate outside the control of NGC or the PES, the allowances made in the standard may no longer be considered to be appropriate by the PES. It is understandable that a PES is reluctant to take account of the output from

Page 3.7

a generator over which it has no control when designing the system to meet the requirements of the PES licence. It may be assumed that unless generators are prepared to enter contractual arrangements with PESs, in order to ensure that generators contribute to the security of supply, it is unlikely that all the theoretical benefits of embedded generation will be realisable in practice.

The minimum level of security that a PES is required to achieve is summarised in Table 3.1.

Table 3.1 Normal levels of security required for transmission and distribution networks

Minimum demand to be met afterClass ofSupplyA

Range of groupDemandup to 1 MW

First circuit outage Second circuit outage

In repair time: Nil

Group Demand

B over 1 to 12 MW a) Within 3 hours; Nil

group demand minus 1MW

b) In repair time ;

Group Demand

C over 12 to 60 MW a) Within 15 minutes; Nil

SMALLER OF (GROUP DEMAND

MINUS 12MW) AND 2/3 GROUP

DEMAND

b) Within 3 hours;

Group Demand

D over 60 to 300 MW a) Immediately; c) Within 3 hours;

GROUP DEMAND MINUS UP TO FOR GROUP DEMANDS GREATER THAN 100MW,

20MW (AUTOMATICALLY SMALLER OF (GROUP DEMAND MINUS 100 MW) AND

DISCONNECTED) 2/3 GROUP DEMAND

b) Within 3 hours; d) Within time to restore arranged outage;

Group Demand Group demand

E over 300 to 1500 MW a) Immediately; b) Immediately

GROUP DEMAND ALL CUSTOMERS AT 2/3 GROUP DEMAND

c) Within time to restore arranged outage;

Group demand

F over 1500 MW In accordance with CEGB planning memorandum PLM-SP2 or Scottish Board

Security standard MSP 366

Page 3.8

Table 3.1 classifies distribution system in terms of the “group demand” supplied, which for a single site is defined as

“The appropriate estimated maximum demand given in the adopted load estimates or the Area Board’s own estimates for those points for which no load estimates have been adopted.”

and multiple sites is defined as

“The sum of the appropriate estimated maximum demands in the adopted load estimates with allowance for diversity appropriate to the Group, or the Area Board’s own estimates for those parts of the system for which no load estimates have been adopted.”

It therefore follows that any given site will be supplied buy a network that will have increasing levels of security of supply. A low voltage domestic customer with a demand (i.e. a single site group demand) of 2 kW will have a Class A supply. This domestic customer may be supplied from a secondary 11/0.415 kV substation that has a total maximum demand of 200 kW, which therefore also has a Class A supply. The secondary substation will be supplied from a primary substation that may have a maximum demand of 10 MW, thereby giving a Class B supply. By continuing the analysis back up thorough the distribution system to the transmission system “group demands” increase and the class of supply increases accordingly.

A first circuit outage, in Table 3.1, signifies a fault or an arranged circuit outage, although consumers with classes C to F of supply should not be interrupted by arranged outages. A second circuit outage generally signifies a fault condition occurring during an arranged outage. The table defines minimum demand that should be met for different classes of supply after outages. For class A supply (those group demands of 1 MW of less) P2/5 recognises that a single outage on that group is likely to affect the whole group and so the time taken to identify and repair the fault, and to restore the circuit to service (the repair time) is the only appropriate criteria to apply.

It should be noted that at least two PES companies have adopted slightly modified security standards to suit their particular circumstances.

It can be seen that the requirements for security of supply depends upon the demand supplied by a group. In a similar way the effect of generation depends upon the type and size of generation and its operating regime. In P2/5 the effect of different types of generators on system security is assessed by consideration of the characteristic operation of each type of plant. It is reasonable to assume that an embedded generator will contribute in some measure to the security of the supply when it is operating, notwithstanding reactive power requirements, concerns about islanding conditions and the variability of the output from the generator. A station that normally generates electricity throughout the day (i.e. a base load station), every day that it is available will obviously have the greatest contribution to the long term security of supply, whereas peak lopping or units that operate with a low load factor will make a much smaller contribution.

For most distribution networks there is generally no requirement for the group demand to be met immediately after a fault or outage condition, and so embedded generators with a short start-up time may be considered as being able to add to the overall system security, providing suitable agreements

Page 3.9

can be reached with the host PES. Table 3.2 summarises the effective contribution of generation to network capacity as defined in P2/5, but it must be stressed that the PES must be able to place reliance on the availability of this generation if the benefit indicated in P2/5 is to be realised.

Table 3.2 Effective contribution to network capacity

Type of generation Contribution afterfirst circuit outage Classes of supply

A-E

Contribution aftersecond circuit outage Classes of supply D

and E only

Notes

Base Load steam units 67% Declared Net

Capacity

67% Declared Net

Capacity

Load Factor 30% or above

Gas Turbine Units 67% DECLARED NET

Capacity

67% DECLARED NET

CAPACITY

The contributions should be restricted to

SUPPLYING THAT PART OF THE DEMAND WHICH IS

NOT REQUIRED TO BE SUPPLIED IMMEDIATELY

FOLLOWING THE 1ST OR 2ND CIRCUIT OUTAGES,

AND/OR TO RELIEVING SHORT TERM OVERLOADS

OF TRANSMISSION OR DISTRIBUTION CIRCUITS

FOLLOWING SUCH OUTAGES

OTHER STEAM PLANT:

Day-Plateau

or Day Plateau &

Peak Units

SMALLER OF 67%

DECLARED NET

Capacity

OR 20% OF GROUP

DEMAND

FOR CLASS E ONLY;

SMALLER OF 67%

Declared Net Capacity

OR 13% OF GROUP

DEMAND

Medium load factor:

10% to 30%

Peak Load Units only SMALLER OF 67%

DECLARED NET

Capacity

OR 10% OF GROUP

DEMAND

SMALLER OF 67%

Declared Net Capacity

OR

7% OF GROUP DEMAND

Low Load factor

Below 10%

3.2.2 Quality of SupplyThe PES companies are required, as part of their licence conditions, to meet standards that relate to the quality of supply provided to a customer. These standards are incorporated in the Guaranteed Standards and Overall Standards that set the service levels that customers in a PES area should receive. The Guaranteed Standards cover 10 service areas, of which three specifically relate to the quality of supply provided by their distribution business. The Overall Service standards also cover 10 service areas, of which three primarily affect the distribution business. As quality of supply is an issue that relates to the connection of embedded generation the relevant standards are summarised in Table 3.3.

The PES is therefore obliged to ensure that a generator connecting to its system will not adversely affect either the quality of the system voltage or the ability of the system to recover from fault conditions. In fact PESs are, under pressure from OFFER, setting individual long term targets that

Page3.10

reduce response times for OS1 and OS3. These are some of the issues that are considered during the assessment of a connection application.

Table 3.3 Summary of Standards that a PES must achieve that relate to embedded generation

Standard Covering CommentsGS2 Restoring supply after a

fault within 24 hoursPES must make payments customers if they fail to meet this standard, with addition payments for each further 12 hours

GS5 Notice of interruption PES must give customers at least 2 days notice of interruption, or else make payments to customers.

GS6 Investigation of voltage complaints

PES must visit or give a substantive reply within 10 working days of receipt of a complaint, or else make payments to thecustomer.

OS1a&OS1b

Restoration of supplies Supplies should be restored within 3 hours in a minimum percentage of cases and within 24 hours in a minimum percentage of cases

OS2 Voltage complaints Voltage faults to be corrected within 6 months in a minimum percentage of cases

3.3 Summary of conditions required to be met by an embedded generatorAny generator wishing to connect to a PES network must have entered into a number of agreements in order to connect the generator to the distribution system, with separate agreements to trade the electricity generated. They will also need to obtain consents to operate the generator and discharge any by-products into the environment, as well as planning consent to construct the power station. The following summarises the basic conditions that an embedded generator must satisfy before it can become operational:

1. A connection agreement between the generator and the distribution system operator. This connection agreement would be based on a formal commercial offer for connection produced by the PES following an application and data submission from the generator.

As part of the connection agreement there will be a Operational Procedures Document, a description of the metering arrangements, a description of the connection arrangements and a definition/quotation of the charges for Use of System. The Connection Agreement will also make reference to operational restrictions and constraints that may be imposed by the PES and NGC. These arrangements are often separated into Technical and Operating Agreement between the PES and the generator and a Meter Operating Agreement. If the generation is intended to supply an existing site demand there is likely to be a requirement for the existing connection agreement with the PES to be modified from a conventional supply to a “standby and top-up supply” agreement.

2. An agreement with NGC, either a bilateral agreement or the generator must be a signatory to the Master Connection and Use of System Agreement (MCUSA). The generator may also sign an Ancillary Services Agreement with NGC.

Page3.11

3. A generation licence, or exemption from such a licence. Generators with a capacity of less than 100 MW that exports less than 50 MW, or generation that exports 10 MW or less, are exempt from requiring a generation licence.

4. Section 36 consent under the Electricity Act 1989, or exemptions from consent. This consent is required to build or extend a power station, but power stations with capacity of 50 MW or less are exempt from Section 36 consent and require only local planning permission

5. Section 37 consent under the Electricity Act 1989, or exemption from consent. This consent is required to build a new overhead line.

6. Section 14 (parts 1 and 2) consent under the Energy Act 1976, for gas fired generators only, but generators with a capacity less than 10 MW are exempt from these consents

7. IPC consent for emissions.8. Local authority planning permission under The Town and Country Planning Act 1990 (section 90).

For power stations requiring Section 36 consent local planning permission is included in the granting of the Section 36 consent.

9. A method by which the electricity may be traded, through either a Power Purchase Agreement with another party, a second tier supply licence, a second tier supplier or through the Pooling and Settlement Agreement. The generator will need to agree a series of Loss-Adjustment Factors (or line loss factors) with the host PES distribution business that enable the generator to be paid for his effective output relative to the GSP.

10. Construction agreements to cover the connections works

At present developers of embedded generation projects are faced by some major difficulties to the development of new schemes. All developers generally face some objections from the local community at a local planning level, depending on the nature of the local area and the national importance attached to protecting that specific environment and on the sensitivity of the local community. This is particularly true for larger gas fired power stations and wind farms. The developers of gas fired generation schemes face difficulties in obtaining Section 14 and Section 36 consents under the present government moratorium on gas fired generation following the issue in October 1998 of the white paper (Conclusion of the Review of Energy Sources for Power Generation) outlining the government’s current energy policy. In a number of cases the final instrument that objectors use to hinder the prospects for a new generator is section 37 consent, in effect consent to physically connect the generator. Objections to the construction of a new line are generally the last to be heard and as such can be used as a final opportunity for objectors to co-ordinate their opposition to a generation project.

3.4 The effect of the Review of Electricity Trading Arrangements (RETA)There have been claims by a number of affected parties that the present electricity trading arrangements may have lead to excessive electricity prices and that the present market is open to the risk of “gaming” by large generators. The Review of Electricity Trading Arrangements (RETA) was initiated by the Minister for Science, Energy and Industry and is being led by OFFER in order to address concerns regarding the complexity of bidding and price setting, levels of prices and the lack of liquidity in the contracts market under the present arrangements. The method by which all generators receive a uniform system marginal price (SMP) for the energy they supply, which in practice only reflects the price bid by a few large generators, has led to concerns that the market can be manipulated and that the prices paid to generators do not reflect their true costs. The balance of the

Page3.12

market in favour of the generators and the lack of significant demand-side participation is an undesirable characteristic for a competitive electricity market, and so the need for revised trading arrangements will seek to tackle such issues. Other aspects of the present market that are perceived as being unreasonably balanced toward the generator, such as capacity payments, are also being addressed in RETA.

It is intended that the proposed revised electricity trading arrangements are to put in place arrangements that are more in line with those adopted in other commodity markets. These proposed markets are to include a long term forwards market, an organised short-term bilateral market that operates from 24 hours to 4 hours ahead of each trading period, and a balancing market operating from 4 hours ahead of each trading period. In England and Wales, the System Operator (presently NGC) would be expected to balance the system, deal with transmission constraints and maintain security of supply using the resources available within this market structure.

RETA is therefore expected to result in fundamental changes in the way that generators trade their output energy, which is likely to affect the way embedded generation schemes are operated; It has already been proposed that the electricity pool ceases to exist. RETA may also affect the nature of the commercial relationships between the PES companies and embedded generators. At the time of writing this report the RETA had not been finalised and there was insufficient information available regarding the proposed trading arrangements to enable a thorough assessment of RETA, but we provide a commentary based on recent publications and discussions.

3.4.1 How RETA is likely to affect the PES companiesOne of the key issues for implementing the proposed trading arrangements is that the supply and distribution functions of the PES companies are separated. If the trading arrangements are extended into Scotland there will be a need for further separation with regard to the generation and transmission businesses of the two Scottish PES companies.

In England and WalesIn England and Wales many of the PES companies have already taken steps to ensure separation between their different business activities, whilst retaining some common service facilities such as customer call centres and information technology resources. The separation of businesses is therefore already fairly well advanced in some areas, with minimal overlapping of responsibilities within organisations. This separation of business has been driven, to some degree, by the need to provide separate accounts to OFFER for the distribution and supply businesses and also to demonstrate compliance with the requirements of the PES licence to prevent cross subsidisation and to treat all users of the system in a non-discriminatory manner. In order to define the role of the separate businesses it will be necessary to modify the existing PES licences and create separate licences for each business function. Although there will be some way to go before there is complete separation of the PES businesses in England and Wales, which may also include some additional cost, it is likely that this process could be completed before the forecast implementation date for RETA.

Once PES business activities have been separated it is likely that there will be an increased level of interest in purchasing the supply companies by major generators, as they will seek to minimise their risk exposure in the new market. This may tend to lead to a relatively small number of combined

Page3.13

supply and generation businesses, as is happening at present, but will still provide opportunities for new entrants in the generation and supply markets. The market in England and Wales has already seen a growth in the participation from Second Tier Suppliers, which are mainly companies with significant generation resources, and this trend will no doubt continue. It is important to recognise that under the new trading arrangements there will only be a class of “suppliers”, with no distinction between the present Second Tier Suppliers and PES suppliers and the concept of a supplier’s “own” area will cease to exist, the geographic ownership remaining with the distribution business.

The distribution businesses will present a very different type of asset to potential investors compared with the supply businesses, as the revenue generated should be relatively steady but relatively small as the market participation will be limited. The supply businesses, on the other hand, present the opportunity for investors to make larger returns, but at a higher risk. However, the activities of the distribution companies will need to reflect the revised trading arrangements. The distribution businesses will need to ensure that they have connection agreements with customers that properly address the degree of risk that they will be exposed to under the new arrangement. The instigation of standard agreements for use of system, metering, and data collection between the PES distribution company and the PES supply company should enable the distribution business to offer similar agreements to other suppliers and embedded generators. The separation of businesses should also enable more open discussions to be held with the developers of embedded generation schemes if there is no commercial or organisational links between the distribution, supply and generation aspects of the PES. If a generator does decide to purchase a distribution business, however, it is likely that the generator will be prohibited from connecting generation to the distribution system owned by that business.

In ScotlandIn Scotland there is presently no pool and new entrants in the generation market tend to enter bilateral contracts with suppliers, either the host PES or a Second Tier Supplier (STS). The PES must purchase any “spill” generation that results from generation in excess of the contracted demand and provide a top- up supply to cover a generation shortfall. This service is covered by a “Residuals Agreement”. The amounts payable for the spill generation and top-up supplies are linked to the pool prices in England and Wales, so it is inevitable that there will need to be a modification to these arrangements once the electricity pool ceases to exist.

The vertical integration of the business in Scotland is such that although there are licence obligations on the PESs to make the transmission system available to other companies on terms which neither prevent nor restrict competition in the supply and generation of electricity, relatively little independent generation and supply has emerged, in comparison with England and Wales. The need to encourage greater competition in the Scottish electricity market has lead to OFFER considering alternative trading arrangements. However, the time-scale for implementing such changes is likely to coincide with the start of the new Scottish Parliament and so political considerations may delay or prevent the implementation of any fundamental changes to the present arrangements. The alternatives under consideration can be summarised as falling into three main categories:

1) a continuation of the present arrangements, with some modifications to reflect the levels prices should be based against if the Pool ceases to exist.

2) the development of Scotland-wide trading arrangements

Page3.14

3) the development of trading arrangements that incorporate England, Scotland and Wales

The present arrangements in Scotland will require some modifications to deal with the scheduling, despatch and economic operation of a significant capacity of new independent generation schemes in the PESs area. These changes include modifications to the Scottish Grid Code, possible changes to the PES licences and changes to contracts relating to top-up and spill payments. Such issues are being considered at present in parallel with discussions related to the separation of business activities.

The development of a Scotland-wide trading area, combining the system operation functions presently performed by Scottish Hydro-Electric and Scottish Power, will require a significant review of the existing operating procedures for each company. The diverse nature of the electrical systems in Scotland may mean that ancillary service payments to existing generators in remote parts of the system together with the increased administration will result in increased operating costs. The development of Scotland-wide trading arrangements may be considered as an intermediate step to the long term goal of a trading arrangement for Great Britain, but it is perhaps questionable if the aim of promoting competition in Scotland will be best served in this way. The main limitations to the creation of real competition in Scotland would appear to be presented by the existing over-capacity of generation plant, the relatively small demand and the capacity of the interconnector to England. Once the interconnection to Northern Ireland is in service and the capacity of the Scotland -England interconnector is increased to 2200 MW there will be increased opportunities for new entries. It is therefore possible that the proposed modifications to the existing arrangements may be sufficient to develop more competition in the Scottish electricity market.

General factors for PES companiesRETA will have an impact on a number of the commercial arrangements that PES companies have in place, particularly those that relate to trading relative to the pool price. This applies to existing NFFO contracts that will need to be re-written, as at present the PES is refunded the difference between the cost of the energy he purchases from that generator (the generator’s bid price) and the cost of electricity he would have purchased from the pool (PSP). The fossil fuel levy is used to fund these payments. The abolition of the pool means that the PES company should be recompensed for the energy purchased from the renewable generator in terms of a new reference price, which is yet to be agreed.

For future rounds of NFFO it is a matter of some debate how the system will work. At the moment there is an obligation on the PES companies to take the output from these renewable generators (under Sections 32 and 33 of the Electricity Act) and the PESs are refunded the additional cost of purchasing this energy. In the future if a PES supply business is to compete on an equal basis as other suppliers it is unreasonable to compel them to purchase electricity from any specific producer. An alternative solution may, therefore, be an agreement whereby the renewable generator is paid a subsidy directly by the NFPA for every unit of electricity supplied.

Page3.15

3.4.2 How RETA is likely to affect embedded generatorsThe reform of the electricity trading arrangements will affect the commercial arrangements that embedded generators will enter. It is not thought that the changes will reduce the attraction of NFFO contracts, but it is perhaps inevitable that there will be some initial concern amongst potential developers and existing generators that the commercial terms will enable projects to be economically viable. Once such generation schemes reach the end of their NFFO contracted period then it is likely that they will enter similar commercial arrangements as at present, that is sell their generation to a supplier who specialises in the trading of “green energy”. The opportunity for renewable generators with a variable output to trade in the potentially lucrative short-term bilateral, or “four hour” market could be considerable, as with suitable technology it is feasible that a wind or wave energy generator could be able to predict its output in such a time scale. This may enable a renewable generator to sell part of its output that it is confident that it will be able to supply to a supplier through a long term contract, and trade the remaining, less predictable short-term weather dependant output in the four hour market. However, one of the overall objectives of RETA is to bring about a reduction in the price of electricity, in the order of 10%. A reduction in the price of electricity could reduce the competitiveness of generation from renewable sources in the short term, as the cost of electricity from these sources has only recently started to converge with the costs from conventional stations.

The prospective operating arrangements for non-firm generation is not clear at this stage, but it is possible that their output could be traded in the balancing market. However, it is likely that NGC will set a minimum level of generation export capacity that can be traded in the balancing market, in order to enable them to operate the market effectively.

Fossil fuelled embedded generation generally establish bilateral energy supply contacts prior to their construction in order to secure the project economics. These generators should, therefore, be able to adapt to the new market structure without too much difficulty. However, many embedded generation schemes are installed with a view to capitalising on the Triad benefits. It is not clear at this stage how these benefits will be treated under the new trading arrangements, but as the new arrangements are intended to promote demand side management it is expected that incentives similar to the Triads will be put in place which will lead to continued interest in the construction of generation projects by customers with relatively high electrical demands. Generators whose output is stable and predictable over a year or even some shorter period of time should be able to secure reasonable contracts in the forwards and futures markets. Many CHP schemes that are designed to match the steam demands of a site may not be able to accurately predict their future electrical output more than a few hours ahead, hence these schemes will have less confidence in trading in the forwards and futures markets. These schemes will therefore be better suited to trade in the short term bilateral market. The present market arrangement requires generators who wish to sell electricity through the pool to submit bids a day ahead of trading and so many CHP plants are not able to participate in this market. The new trading arrangements should therefore increase the scope for CHP plants to maximise the revenue from their electrical output.

If a generator has an uncertain output then it is possible that suppliers will be unwilling to accept the risk of a generator failing to provide its promised power. In order to minimise this risk a supplier or trader will either reflect this risk in the contacts with the generator, so that the generator becomes liable for a failure to supply, or increase the number and range of generators in his portfolio. The range of options and contracts that a generator can make should enable each embedded generator to

Page3.16

determine the best arrangement to match his particular operating characteristic. The proposed format of the revised electricity trading arrangements include the possibility of trading security as a separate commodity. The trading of security should enable PES companies to make better use of embedded generation to defer system reinforcement providing suitable commercial arrangements can be agreed.

Page 4.1

4. THE ABILITY OF THE UK DISTRIBUTION NETWORKS TO ACCEPTEMBEDDED GENERATION

The ability of the distribution networks in the UK to accept new embedded generation schemes varies from region to region and also within each region there may be major differences between how much generation may be accepted. Although each distribution system was designed to the same planning standards, the design of the networks and the development of the networks varies as a consequence of many different factors. Economic and political considerations may have lead to significant increases or decreases in the loads supplied from a particular network, there may have been a marked increase in embedded generation, such as that caused by the “dash for gas”, or changes in the transmission network may have resulted in higher system fault levels on the lower voltage networks. In order to obtain sufficient information to enable an assessment of the ability of the distribution systems to accept more embedded generation we approached the PES companies directly to elicit both their views and facts about their system.

In this section we summarise the responses from each of the 14 PES companies to indicate the regional scope for increases in generation and to identify where there is a clear need for improvements in the system. For each PES company we include a brief description of the distribution system in their area, the existing levels of embedded generation, the capacity for more embedded generation, the network planning strategies adopted when considering both generation applications and for general system development.

4.1 The ability of distribution systems to accept embedded generationThe development of the electrical power systems in the UK is outlined in Section 3.1 of this report, and in general it is true to state that distribution systems have been designed to be passive systems, transporting power from the high voltage transmission system, or from generators connected at key locations on the 132 kV networks, to consumers at lower voltages. The distribution systems were therefore generally designed with the requirements of load customers as a primary concern. When a new load is connected it increases power flows in the distribution system, generally reduces the voltage at the connection point and, depending upon the characteristics of the load, may increase system fault levels. For the connection of a typical new load however, the increase in fault level is normally small and is of much less concern to the PES than the increased power flows and volt drops. When a generator is connect to a distribution system it can significantly change the way in which that system operates. The capacity of the generator may be such that it either matches or exceeds the connected load in the local network, which in the extreme may cause power to flow from the local distribution network back into the higher voltage network. This can cause power system protection to operate incorrectly and voltage control schemes to fail unless remedial action is taken. Experience has shown that in general, for connection of embedded generators to be successful, the capacity of embedded generation on a system should not exceed the minimum demand on that system. The point at which a generator is proposed to be connected on a system also has an important influence on the capacity of generation that may be connected and the degree of reinforcement required to accept the generation.

Page 4.2

The effect of location on the acceptable generation capacity that may be connected to a distribution system may by broadly assessed by considering Figure 4.1. A generator connected to a source substation (point A in Figure 4.1) will often afford an easier connection as volt drops are minimised and it is easier to co-ordinate the generator voltage control scheme with substation automatic voltage controller. A direct connection to a substation will tend to result in simpler protection schemes and it should be easier to achieve a suitable site earthing. However, in order to connect directly to an existing substation it may be necessary to extend that substation, which may result in an overall cost greater than that for a connection to an overhead line.

Connections that are made away from a source substation (point B and C in Figure 4.1) will tend to cause voltage drops due to power flows through line impedances, therefore voltage control issues may limit generation capacity. In some cases (point C) the thermal capacity of the circuit conductors may need to be increased in order to accept the generation.

A number of protection philosophies are used on distribution systems. Common types of protection schemes employ an Inverse Definite Minimum Time (IDMT)schemes, unit protection schemes or distance protection schemes.

IDMT protection schemes use an overcurrent relay in which the time delay varies inversely with fault current up to a certain value, so it tends toward a minimum value. The fault clearance times associated with IDMT schemes tend to be longer than those used in other protection schemes, which can lead to transient stability problems for any generation connected to the system.

Unit protection schemes use a fairly simple concept of measuring and comparing the current at two ends of a circuit. If there is a difference between the currents at each end of the protected circuit then there is a fault in the circuit. Unit protection schemes are protected individually without reference to other sections and are the connection of a generation to a line that is protected with unit protection will obviously require some changes to the system protection.

The connection of generation on the mid point of a line may cause problems with power system protection that usew distance protection schemes. The main problems that could be experienced are under-reach and tripping due to power swings. Many protection schemes employ impedance measuring distance protection relays. These relays measure the effective line impedance by measuring the system voltage and the current flowing in a feeder and are set to operate when the impedance is at such a value that indicates that there is a fault on the network. If a generator is connected to a line protected in such a way then if a fault occurs on the section of line between the generator and the distance protection relay the relay will operate correctly. If a fault occurs on the line between the generator and the line end then the generator will feed the fault and the fault current from the source substation will be reduced, which may cause the protection not to “see” the fault. This is referred to as under-reach and there is a requirement for additional protection schemes to be installed to cater for such an event. If, under non fault conditions, the generator trips from full load there will be a sudden change in power flows on the feeder connecting the generator to the source substation which may cause the impedance measured by the protection to momentarily pass through the relay operating zone. Such a power swing will require additional protection equipment, power swing blocking relays to be installed. In some areas a generator may face difficulties achieving an earthing level to limit the earth potential rise under fault conditions that may require the generator to install a

Page 4.3

much larger earth mat than originally intended, or to take steps to ensure that increased earth potential rises do not result in excessive voltage levels that may pose a risk to people or equipment.

Figure 4.1 Sample 33 kV network

Page 4.4

4.2 Northern Scotland - Scottish and Southern EnergyScottish & Southern Energy (SSEH-E) own and operate the Scottish transmission and distribution systems in Scotland north of Glasgow, Bonnybridge, Kincardine and GlenrothesGlasqow, Edinburgh and the county of Fife. The SSEH-E Scottish region also includes the Kintyre Peninsula, the islands of Arran, Coll, Mull, Islay, Tiree, Orkney, Shetland and those in the Western Isles.

The main transmission system in the SSEH-E area operates at 275kV & 132kV between the north and south of the areaHydro-Electric area., which is supported and augmented by 132kV networks The 275kV network runs up the east coast from the border with Scottish Power in Fife, past Dundee and up to Aberdeen, linking in the power station at Peterhead. From Aberdeen, a double circuit 275kV towerline runs west to Inverness then a single circuit runs north to the site of the former Dounreay powerstationextends from Edinburgh to Aberdeen and Inverness in the east, connects to the pumped storageunits at Foyers by Loch Ness, and the Dounreay nuclear facility on the northern Scottish coast. The distribution systems in the SSEH-E area predominately operate at 33kV and 11 kV.T with many systems having small generating stations that can meet much of the local load.The distribution system has a range of Many of the generators with individual capacities of less than 1 MW are connected at lowvoltage (415V). The majority of thesembedded generating stations. A number of these are hydro stations operated by SSEH-E, but there are also a rangenumber of privately owned generators and renewable energy schemes connected under Orders of the Scottish Renewable Obligation. In the SSE region the transmission connecting generation includes several of the larger hydro stations, the Foyerspump storage station (2 x 150 MW) and Peterhead power station (dual qas/oih. TheH-E also have a large gas fired power station at Peterhead 1524 MW) Peterhead power station, tbatlocated approximately 50 km north of Aberdeen, is currently being re powered but the authorised output remains at 1524 MW.. We understand that the capacity of Peterhead power station may increase to 2150MW by 2000/2001,although the authorised output will remain at 1524MW for some time due to constraints on thetransmission system.

The main load centres in the SSEH-E area are located on the east coast at Aberdeen and Dundee. In the rest of the H-Esystem^ many of the networks in remote areas are characterised as having relatively low demands with long, weak supply feeders. Overall, SSEH-E has a surplus of generation, some of which it exports to customers in England through the Scottish Power network and its share of the England-Scotland interconnector464. The trading arrangements for the England-Scotland interconnector are described in more detail in Section 3.1.3 of this report.

The following summarises some key statistics regarding the SSE-Hydro ElectricArea of land covered (approximate) 54,000 sq. km

Approximate number of customers 641,000

H-E Maximum demand (approximate) 1.55 GW

H-E Minimum demand (approximate) 0.53 GW

Overhead line circuit km 34,135

Underground circuit km 13,760

% of circuits operating at 132 kV 6.7

% of circuits operating at 33 kV 12

% of circuits operating at 11 kV 54.1

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4.2.1 Existing Levels of Embedded generationThere is a total of 1251.6 MW of embedded generation on the SSEH-E network, although 160 MW of this is from diesel generators on island systems which have either no connection (Shetland') or operate in a stand-by mode to cover for submarine cable failure.a relatively weak connection to rest of the H-E network on the mainland. The majority of the embedded generation is from

Page 4.6

conventional hydro generation which is directly connected to the grid system andthat-is mainly located in the west and north of the SSEH-E network^ with an additional capacity of 300MW of pumped storage generation connected to the transmission system at Foyers, at Loch Ness Table 4.2.1 summarises the existing levels of embedded generation connected to the SSEH-E network.

Table 4.2.1 Embedded generation connected to the H-E system by technology

Technology Installed Declared net Capacity (MW)

Hydro 1064

Diesel 160

Hydro under SR01 2.6Wind 17

Waste 8

Total 1251.6

4.2.2 Network Planning StrategiesSSEH-E are conscious of the need to treat all connection applications in a fair and consistent manner and adopt procedures that aim to ensure that this is achieved. In order to comply with the European Voltage harmonisation directive, so that the normal voltage of power supplied to consumers is 230V, SSEH-E have a policy of limiting the voltage on their distribution systems so that when it is transformed through the fixed tap secondary distribution transformers it is within the harmonised limits of +6-10% of 230V. The maximum voltage levels and voltage fluctuations that can be accepted are summarised in table 4.2.2.

The statutory limits for 11 kV and 33kV are +/-6%, however for planning purposes the figures below areused.

Table 4.2.2. Summary of permitted voltage ranges and fluctuation permitted on Hydro-ElectricNominal system Voltage Permitted range Comments11 kV 10.34 kV to 11.132 kV Where there are directly connected customers

10.34 kV to 11.33 kV Where there are no directly connected customers33 kV 31.02 kV to 33.4 kV Where there are directly connected customers

31.02 kV to 33.99 kV Where there are no directly connected customers132 kV ±10%

Voltage fluctuations 1% frequent } In accordance with the spirit of Engineering3% infrequent } Recommendation P28

Voltage change on loss of generation

6% }

For each generation application received a computer based study is performed to assess the effect of the new generation on network load flows, short circuit levels and, if appropriate, transient stability.Load flow studies are performed to confirm that the voltage profiles and voltage fluctuations are within the ranges quoted above and that equipment will operate within its thermal rating. Short circuit calculations are performed in accordance with the procedures described in Engineering Recommendation G74, with SSEH-E allowing a 10% fault level margin between the switchgear rating and the calculated switchgear duty. For applications that are to be connected at 132 kV, or for those connecting at lower voltages that have a capacity greater than about 30 MW, a transient stability study is normally performed.

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4.2.3 The capacity for more embedded generationThe SSEHvdro-Electric network covers a large geographic area and the ability of the distribution networks to accept more embedded generation varies considerably across the region. Approximately 176 MW of renewable energy generators were contracted under the first two SRO orders, of which around 28 MW of SROI generation is already connected. It is expected that at least 50% of the 120 MW to be awarded under SR03 will be for aconnection in the SSEH-E area. There are a number of key bottlenecks that limit the scope for connecting additional generation to the H-ESSE system, which are identified in their Seven Year Statement for 1998 and discussed further below.

SSE response to questionnaireH-E ViewsInformation has been providedobtained in response to a questionnaire and follow up discussions.from separate discussions held with a H-E planning engineer. The SSEH-E advised that their Seven Year Statement provides^ the best high level indication on the ability of their Transmission networks to accept new embedded generation. T At a local level. SSE Wtemphasised tbatthe importance of early consideration of the location and rating of a proposed generator relative to the rating of the local networksystem to which the generation is to be connected.

Hydro-Electric are keen to encourage the connection of renewable generation in their area.However,SSE recognise that there are connection issues a number of problemswith the present SRO process that tend to lead to high connection costs.hinder the developers of generation projects. H- ESSE have made suggestions to the Scottish Office as to how these difficulties may be overcome and in general how the overall process may be improved. One of the major problems with the present SRO process is that the award of a number of SRO contracts in the same area may result in the need for reinforcement over and above that already identified for individual applications: the ‘clustering’ issue. Although developers are made aware of the potential ‘clustering’ costs for their scheme.se eeststhe bid process encourages the applicant to consider only the lowest connection cost provided.generator will submit the lowest bid price to the Scottish Office, which does not reflect the additional reinforcementcosts. This canfras lead to a situation wherea number of contracts have been awarded to generators who form a ‘cluster’ who are then unable tobut cannot proceed due to the high cost of system reinforcements reguired to accommodate the clustered group. A revised mechanism would need to address the issue of ‘clustering’.

At an overall level. The resolution of limitations on the transmission system a rets identified as a major factor that is working against the development of renewable energy schemes in parts of SSE's territorvnorthern Scotland. The SSE Seven Year Statement identifies a number of main 275 kV system bottlenecks but there are also local restrictions on the 132 kV system which was developed in the northand west to accommodate the existing embedded hydro generation. Major reinforcement of the transmission system to accommodate increased levels of renewable energy generation in the north and west brings a number of issues, not the least of which are the Question of who pays for the reinforcement and the visual impact of new overhead lines on the local environment,as H-E do not feel that is appropriate for their customers to carry the burden for paying for such generation relatedimprovements in the transmission infrastructure. Where such improvements would bring an identifiable improvement to the supply H-E would consider the value of this and make an appropriate contribution tothe works. However, unless either the government or developers are also prepared to make asignificant contribution to the works it is likely that such transmission constraints will not be resolved.

Quantitative assessment

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with Hydro-Electric planning engineersWe have derived an estimate for the level of generation that couldmay be connected to the SSEH-E network based on information presented in the SSEHvdro- Electric Seven Year Statement and subsequent^# discussions. Table 4.2.3 summarises the ability of the SSEH-E network to accept additional generation by voltage level and area, although it should be recognised that this should not be taken as an indication of the ability of any particular network to accommodate a specific generation project.

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We have also performed a crude analysis based on estimates of the ability of individual circuit types to accept new additional generation and the overall system limitations indicated in Table 4.2.3. The calculations used to derive the estimates of the capability of the SSE network as a whole to accommodate new generation are included as Appendix B. These analyses suggest that it may be possible for a total of between 110 MW to 350 MW of new generation to be connected to the existing H­E system without performing major reinforcement, providing that appropriately rated generation is connected at suitable locations. Given the capacity of generation that has already been awarded contracts under SRO orders and the likely level of generation that will be awarded contracts under SRO3, it is possible that the capacity for new generation could be restricted to below 110 MW if all of the contracted projects proceed. As in the rest of the UK, the connection of new generation will be expected to displace existing generation, although in the H-E territory there are a large number of hydro generators that may be required to operate for flood control purposes. It is likely that one of the largest opportunities for the development of new generation schemes will be from existing consumers who seek to generate their own electricity on their own site.

At the moment the overall capacity for additional generation is limited by the ability of the transmission system to transfer the power generated to load centres in Central Scotland and England. Once the capacity of the Interconnector to England has been increased it is likely that the amount of power generated in the SSE area will increase although it is likely that reinforcement within the Scottish Power network will also be required.

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Table 4.2.3 Ability of the H-E network to accept new generation by

Region Voltage Capacity

(MW)

Comments

South West - 11 kV, 33 kV, <75 MW It is unlikely that any new generation can be accepted onKintyre Peninsula 132 kV these networks unless the generation is prepared to

accept a non-firm connection or the Sloy-Clachan 132 kVcircuit is reinforced. There is also a transmissionconstraint due to the capacity of the Sloy-Windyhill circuits.

Total <75 MWWestern Isles 11 kV and <5 MW Voltage control problems may be alleviated by the use of

33 kV controllable reactive compensation equipment, although this will be expensive.

132 kV 10-20 MW The transmission system is sensitive to changes in both real and reactive power flows and any new generation and its connection equipment will need to be designed to harmonise with the system’s requirements*

Total (estimate) 20 MWNorth West 11 kV 1-2 MW Voltage control issues the main concern

33 kV 2-5 MW “

132 kV uncertain The power export capability is limited by the main thermal constraints and stability may also be a limiting factor*

Total (estimate) 35 MWNorth East 11 kV 1-2 MW Voltage control issues the main concern

33 kV 2-5 MW “

132 kV <100 MW thermal constraints are the main limitation but stability may also be a limiting factor*

Total (estimate) 120 MWCentral Highlands 11 kV and <10 MW Voltage regulation and Short circuit fault levels

33 kV <25 MW the main limiting factors132 kV <75 MW Constrained by the thermal capacity of the transmission

circuits between Kintore and Tealing, north of DundeeTotal (estimate) 100 MW

* Note Principle difficulty is associated with ability of the transmission system to accept generation, particularly the

circuits between Kintore and Tealing. The connection of new embedded generation may require existing

generation to be contstained off in order to allow satisfactory performance of the transmission system.

Limiting factors for the connection of new generation

In rural areas voltage regulation on the 11 kV and 33 kV systems is the main limiting factor when assessing the connection of new generation. The areas where there is greatest.potential for the development of wind energywmd generation are generally remote from electrical networks capable of accepting generation, as the networks in these areas are typically designed to serve domestic loads and in some cases are single phase supplies, which are normally unsuitable for the connection of new generation. In a number of locations, particularly where there is existing embedded generation, fault levels can limit the generation that may be accepted by a distribution system. Generally voltage

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regulation anc circuit then al limitsis thought to present the main obstacle to the connection of new generation, but fault levels can also be ain the Errochtv (Strath Tav) area around Perth are also a concern. H-E have plans to replace 132kV switchgear at Errochty in 2001, which should remove thispotential limit for the connection of new generation in this area.

OrvPthe 132 kV system and the 275 kV system there are a number of constraints that, due to the nature of the SSEH-E system, limit the amount of generation that can be connected at lower voltage levels. In the south west the power is exported to the Scottish Power system at 132 kV. This 132 kV system has only limited thermal capacity and thea section of line between Clachan and Sloy currently constrainsgoverns how much generation the level of generation that can be connected in Argyll and Bute. At present more than 75 MW of SRO generation has been awarded contracts to connect in this area, but this ‘cluster’ would reguire a major transmission system upgrade.until the thermal capacity of the circuits between Clachan and Sloy are increased then the whole of this generation can not beaccepted under the present SRO rules.

The opportunities to connect new generation in the north east are limited by a thermal constraint on the transmission system between Aberdeen and Dundee. The transmission system in this area will need to be reinforced before any large new generation scheme could be connected, or the new generation would need to displace existing generation in the local area. South of Dundee there is more scope for connecting new generation, but the thermal capacity of the interconnector to Scottish Power's network will limit the generation that could be connected in Tayside, Perth and Kinross unless the new generation displaces existing generation that presently exports through these circuits.

In the north west the main limitation is also related to the thermal capacity of the circuits to the south, particularly via the north east. There are two 275kV circuits that provide the main route for power to be exported from the large number of hydro power stations in the north west. When these hydro power stations are all reguired to be in service, which is sometimes essential for flood control, there is a relatively large export from the north west to the east coast. SSEH-E advise that under such conditions there is no spare capacity to transfer new generation over to the north east. The opportunities for new generation in the north west must therefore be considered as being limited to those available to customers that wish to supply their own demand.

4.2.4 Experience of Hydro Electric in dealing with Embedded generationSSEHydro-Electric have experience in operating a system with a large proportion of embedded generation, but this is almost exclusively conventional hydro.mainly generation that is under its own control. The introduction of generation that is not controlled by H-E, that is generation with a capacity ofless that 5MW or renewable generation (such as that awarded contracts under orders of SRO) hasresulted in some operating difficulties for H-E. Such difficulties include load forecasting errors,increased system losses and greater administration in order to arrange system outages formaintenance. Hydro-Electric have one operational wind farm on their system at the moment as thelarge 3MW Burger Hill experimental wind generator on Orkney has not operated for some time. Hydro-Electric have noted that the number of voltage complaints on the network where the wind farm isconnected have increased since the wind farm became operational. H-E are presently investigatingthese voltage complaints. Although the wind farm itself is not thought to be directly responsible for thesevoltage problems, it is possible that the complex interaction between the wind generators and otherloads on the system causes system voltages that are occasionally outside the normally acceptable

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tirmterAlthough a large number of SRO contracts have been awarded the number of schemes presently in service is low and so SSE’s operational experience of connected SRO generation is relatively limited. Although detailed connection design work is undertaken, there may be issues with the complexinteraction between large groups of induction generators and a relatively weak system. SSE is carefullymonitoring these effects as new generation comes on stream.

4.3 Central and Southern Scotland - Scottish PowerScottish Power own and operate the Scottish transmission and distribution systems in central and southern Scotland. The Scottish Power territory includes the major conurbations around the cities of Glasgow and Edinburgh and the sparsely populated areas of the southern uplands and the boarders. The main transmission system in the Scottish Power territory operates at 400 kV, 275 kV and 132 kV is connected to the NGC transmission system to the south and the SSE network to the north. The distribution system in the Scottish Power territory operates at voltages of 33 kV and below. There are

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a number of large generating stations connected to the transmission system in the Scottish Power area and there are also a number of generators embedded within the distribution system. These embedded generators include renewable energy schemes that were awarded contracts under Orders of the Scottish Renewables Obligation.

Overall, Scottish Power has a surplus of generation, the majority of which is exported to England through its share of the Scotland - England interconnector. The trading arrangements for the interconnector are described in more detail in Section 3.1.3 of this report.

The following summaries some key statistics regarding the Scottish Power networkArea of land covered (approximate) 22,950 sq. km

Approximate number of customers 1,854,000

Scottish Power Maximum demand (approximate) 4.2 GW

Scottish Power Minimum demand (approximate) 1.5 GW

Overhead line circuit km 25,931

Underground circuit km 39,287

% circuits operating at 132 kV 2.5

% circuits operating at 33 kV 7

% circuits operating at 11 kV 48

4.3.1 Existing Levels of Embedded generation i.e. connected to 33 kV and belowScottish Power have advised that they have approximately 52 MW of embedded generation connected to their distribution system, at 33 kV and lower voltages. From information presented in their Seven Year Statement for 1998/99 we estimate that there is a total of about 522 MW of generation connected at 132 kV and lower voltages. The embedded generators consist mainly of combined heat and power plants, wind energy schemes, hydro, biomass and landfill gas generators. The majority of generation schemes are connected at 33 kV. Table 4.3.1 summarises the embedded generation in the Scottish Power territory.

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Table 4.3.1 Embedded generation connected to the Scottish Power system by technology

Technology Installed Declared net Capacity (MW)CHP 19*Wind 15Hydro 2Bio-mass 12Landfill gas 4

Total 52

* Note Scottish Power advised that this figure may include some discrepancies, depending on the information provided by the

customer. In some cases the information recorded may detail the power that may be exported to the Scottish Power system,

whereas in other cases the information may include the full generation capacity on the site (including those of standby

generators). However, for the purposes of this study it is assumed that the information is accurate.

4.3.2 Network Planning StrategiesScottish Power are conscious of the need to treat all connection applications in a fair and equitable manner and have procedures that aim to ensure that this is achieved. For each formal application received a computer based system study is usually performed, which includes load flow and short circuit studies. Transient stability studies are not normally undertaken, but Scottish Power will advise customers of situations where they consider that transient stability issues may affect the operation of the generation. In such cases Scottish Power consider that it is the generators responsibility to ensure that the generator can remain stable, as protection will ensure that the Scottish Power system remains intact.

Short circuit studies are performed in accordance with the principles described in Engineering Recommendation G74. Although Scottish Power have no formal policy regarding a fault level margin that should be allowed between the switchgear rating and the prospective fault duty, Scottish Power advised that when an initial assessment of a generation project is performed they would aim to have at least 5% margin, to allow for inaccuracies in data used in the studies. If the initial assessment indicated a margin of less than 5% between the switchgear rating and the prospective duty Scottish Power would perform a more detailed study and would, in theory, be prepared to allow the prospective fault level to reach the switchgear duty.

Scottish Power design their system to maintain voltage fluctuations within the limits described in Engineering Recommendation P28, which have a non-linear relationship with fluctuation frequency. However, as a general guide the limits can be more simply defined as a 1% change in voltage for frequent fluctuations (those with a repetition rate of once every 10 seconds) and a 3% change for infrequent fluctuations (those with a repetition rate in excess of once every 10 minutes). A voltage change of up to 6% on the loss of generation from full load can be accepted.

4.3.3 The capacity for more embedded generationThe capability of the Scottish Power distribution network to accept more embedded generation varies across the region. In rural areas the distribution system has a relatively low demand but has the main potential for wind generation and one area in Fife has seen a large increase in connection and feasibility studies for generation. The ability of the Scottish Power system to accept additional

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generation is determined by the different issues that are presented by the characteristics of the networks in each geographic area.

Scottish Power’s Views

Information has been obtained in response to a questionnaire and from separate discussions held with Scottish Power planning engineers. There is some potential for generation connected direct to most GSPs but each site requires to be assessed individually. Similarly, connection to the 33 kV, 11 kV and LV systems may be possible. The main constraints are thermal capacities, fault level and voltage regulation and again individual assessment is required. Generally it is advised that developers make early contact with Scottish Power to discuss their proposals. The opportunities to connect embedded generation varies across the diverse rural and rural networks. It is known that there is a large potential for wind generation within the Scottish Power territory, however as this is mostly located in rural areas with relatively weak distribution systems it would require reinforcement and extension of the transmission system to utilise this potential.

Quantitative assessment

Based on information presented in the Scottish Power Hydro-ElectricSeven Year Statement and simplified analysis of the Scottish Power distribution system^ with Hydro-Electric planning engineerswe have derived an estimate for the level of generation that couldmay be connected to the Scottish PowerH-E network. Based on information contained in the Scottish Power Seven Year Statement we have assumed that the following amount of new generation capacity could, in theory, be connected to the Scottish Power distribution system

System voltage

Location 11 kV 33 kV

Rural 2 MW 10 MW

Urban 5 MW 20 MW

It may therefore be assumed that it is theoretically possible to connect as much as 1218 MW of new embedded generation to the Scottish Power system, assuming that a large number of generators of an appropriate capacity can be connected at suitable locations on the system. In practice this is unlikely to be realised, as technical, economic, and planning considerations will tend to result in a smaller number of generators with the largest possible capacity being connected at a few locations. We therefore estimate that the Scottish Power system may only be expected to accept a total new generation capacity of about 810 MW. The details of the derivation of this estimate are included in Appendix B. However, in order for this level of new generation to be accepted it will be necessary to displace existing generation or for the export capacity from the Scottish Power territory to be significantly increased, and for access to made available to the interconnector. It is likely that one of the largest opportunities for the development of new generation schemes will be from existing consumers who seek to generate their own electricity on their own site.

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Limiting factors for the connection of new generationLimiting factors to the connection of new generation vary across the Scottish Power territory and will depend on site specific considerations. The limiting factors will generally be thermal capacity in the existing system, fault levels and voltage regulation.

4.3.4 Experience of Scottish Power in dealing with Embedded generationThe Scottish Power system has operated with a number of embedded generators connected for a number of years, therefore Scottish Power have an increasing experience in planning and operating their network with such generators in service. Since privatisation the relationships between the generators and Scottish Power have necessarily changed, in that both the generators and Scottish Power now operate in a more commercial manner which requires more formal contractual arrangements to be put in place between the generator and the host PES. As more generation is connected with different operating characteristics and employing new technologies Scottish Power have advised that they encounter new challenges that enable them to increase their experience and incorporate this experience in future work. An example of how such experience may be applied is in improving the accuracy of the initial advice and indicative connection costs they provide to developers. Overall Scottish Power prefer to discuss the likely connection for a given site with a developer and to identify potential difficulties at an early stage.

Scottish Power advised that generally they have not noticed any of the theoretical benefits that are expected to arise from the presence of embedded generation on their system in practice. The theoretical benefits such as reduced losses, deferred system reinforcement or improved system performance are not realised in some cases because it is not in the commercial interest of the generator to enter binding agreements that would enable such benefits to be realised. Scottish Power have advised that embedded generation has increased their administration requirements and load forecasting errors. Where the embedded generation is from an induction machine it can also have the effect of reducing the system power factor which tends to increase system losses. Scottish Power are concerned that if embedded generation continues to be developed as forecast then the associated additional communications, administration and load forecasting errors will also increase and that the number of nuisance generation trips will increase, which will have an impact on the quality of supply to Scottish Power customers. Scottish Power are keen to encourage discussions and investigations of the technical, commercial and legal issues associated with the large scale development of embedded generation.

4.4 North East England - Northern ElectricThe Northern Electric network covers the area bordered the Scottish border in the north, the north sea to the east, the Pennines to the west and extends to Harrogate, York and Scarborough to the south. The Northern Electric network supplies consumers in Northumberland, County Durham and North Yorkshire.

The Northern Electric network has a number of large conurbations and industrial centres, such as those forming Tyne and Wear and Teesside, as well as extensive rural distribution networks that

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supply small communities away from these large load centres. There are a number of conventional power stations connected to both the transmission and distribution networks in the Northern Electric area. To the North of Tyneside the Alcan smelter at Lynemouth and Blyth Power station feed power into the 132 kV network, in Teesside there are numerous generation projects, the largest of which is the 1875 MW Teesside Power station that connects directly to the transmission system but other smaller units such as Seal Sands 50 MW station that connect at lower voltages.

The following summarises key statistics regarding the Northern Electric distribution system

Area of land covered 14,400 sq. km

Approximate number of customers 1,500,000

Northern Electric Maximum demand 3.85 GW

Northern Electric Minimum demand (approximate) 1.3 GW

Overhead line circuit km 17,176

Underground circuit km 26,035

% of circuits operating at 132 kV 1.9

% of circuits operating at 66 kV 3.8

% of circuits operating at 33 kV 1.7

% of circuits operating at 20 kV 19.2

% of circuits operating at 11 kV 26.0

% of circuits operating at 6.6 kV 1.7

4.4.1 Existing Levels of Embedded generationNorthern Electric have advised that there is 265.8 MW of embedded generation on their network that have an individual capacity of less than 100 MW. Table 4.4.1 summarises this generation by the technology employed. There are also a number of generators that have a capacity greater than 100 MW that are subject to central dispatch connected to the Northern Electric distribution system. The location of a gas terminal at Teesport has helped to encouraged the development of gas fired generation in the Teesside region, although transmission constraints on NGC’s system and the present government moratorium are likely to limit this development. The 240 MW power station at Lynemouth supplies power to the adjacent Alcan smelter with remaining electricity entering the Northern Electric 132 kV system. The nearby Bylth power station supplies 342 MW at 66 kV, which is supplied from the same 132 kV system as Lynemouth. The total generation connected to the Northern Electric distribution system is therefore approximately 848 MW.

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Table 4.4.1 Summary of generation with capacity of less than 100 MW by technology in Northern Electric area

Technology Installed Declared net Capacity (MW)Gas Turbine 50Diesel 13.9CHP 156Wind 5.7Hydro 0.2Landfill gas 9.5Waste 27Gas expansion 3.5

Total 265.8

4.4.2 Network Planning StrategiesNorthern Electric are conscious of the need to treat all connection applications in a fair and consistent manner and have procedures that aim to ensure that this is achieved. For each application received a full computer based system study is performed, which includes load flow and short circuit studies. Transient stability studies are also performed for applications that have a generating capacity of 5 MW or greater.

Northern Electric plan their system so that it complies with the standards referred to in their PES licence, the Electricity Supply Regulations and in particular the Engineering Recommendations pertaining to voltage fluctuations and security of supply (P28 and P2/5). The maximum voltage fluctuation that Northern Electric permit for infrequent voltage changes is 3% of the nominal value, although they advised that a 5% change on loss of generation may be permitted. Short circuit studies are performed in accordance with the guidelines included in Engineering Recommendation G74. Northern Electric advised that they consider there is sufficient margin inherent within this methodology to allow no additional margin to be included between the calculated fault level and switchgear rating.

4.4.3 The capacity for more embedded generationThe capability of the Northern Electric distribution network to accept more embedded generation varies considerably across the region. The different natures of the distribution systems designed to meet the relatively low load densities in rural areas and the urban systems designed to meet the higher load densities and the demands of industry will inevitably result in different capacities for accepting new generation with corresponding different limiting factors, as discussed below.

Northern Electric’s ViewInformation has been obtained in response to a questionnaire and from separate discussions held with Northern Electric planning engineers. Northern Electric advised that they could not suggest how much generation could be accepted by each individual circuit without performing extensive power system studies. However, Northern Electric could indicate areas where there are specific limitations on the ability to accept additional generation and discuss the general ability of the networks to accept new

Page4.19

generation. Northern Electric suggested that voltage regulation issues on rural 11 kV networks would limit the amount of generation to about 2 MW, depending on location. In urban areas fault levels would tend to limit the amount of generation that could be connected to below 5 MW on 11 kV networks, again depending on location. Northern Electric identified network limitations close to Seal Sands in Teesside where thermal loading and transient stability issues are likely to prevent new generation being connected at a voltage less than 132 kV.

Quantitative assessmentBased on our discussions with Northern Electric regarding the ability of their systems to accept new embedded generation we have performed some simplified analysis in order to estimate the total generation capacity that could be connected in the North East of England. In our analysis we have assumed that on average it should be possible to connect the following amounts of generation to different types of distribution system:-

System voltage

Location 6.6 kV 11 kV 33 kV

Rural 2 MW 10 MW

Urban 2 MW 5 MW 20 MW

We have further assumed that approximately 60% of the Northern Electric system can be classified as having a rural characteristic, and 40% as having an urban characteristic. On this basis a crude estimate of the ability of the existing Northern Electric system to accept new generation will be about 668 MW providing that suitably sized generation is optimally located on the distribution system and that interactions between machines can be avoided. However, it is unlikely that it will be possible to connect new generation of this magnitude in practice, and so we estimate that the Northern Electric distribution system may be reasonably expected to be able to accept up to 250 MW of new generation, with approximately 150 MW expected to connect in rural areas and 100 MW connecting in urban areas. The details of the derivation of this estimate are included in Appendix B.

Limiting factors for the connection of new generationIn the Teesside area there are limitations to the connection of new generation that are imposed by the available spare thermal capacity and transient stability considerations. This situation particularly applies in the Seal Sands area where Northern Electric have indicated that any new generation must be connected at 132 kV due to limitations at 66 kV and lower voltages. In other urban areas there are limitations on the generation that may be connected at 11 kV due to fault level limitations. In rural areas voltage regulation will limit the generation that may be accepted.

4.4.4 Experience of Northern Electric in dealing with Embedded generationNorthern Electric have a large number of embedded generating stations connected to their system and their experience to date is that these generators have contributed very little of benefit to the overall performance of the system. Northern Electric have been able to defer some system reinforcement in one area by agreeing an availability contract with an embedded generator, but otherwise Northern Electric could not identify any other tangible benefits. There are a large number of CHP schemes in

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operation in the north east that cause serious load forecasting difficulties for Northern Electric, as only ‘net’ metering is provided. Overall the embedded generators increase the administration and data handling that Northern Electric must complete and as the numbers of generators increases then the voltage control difficulties experienced also increase.

4.5 North West England - NorwebThe electrical distribution networks in Cumbria, Lancashire, parts of North Yorkshire Dales and Greater Manchester regions are owned and operated by Norweb. The Norweb system has a mixture of urban networks that supply the high load density areas such as those found in Manchester, and rural networks that supply the lower load density communities in parts of Cumbria, Lancashire and in the western Yorkshire dales. There are two grid supply points that supply Cumbria, Harker near Carlisle and Hutton near Kendal. The supplies to bulk supply points within Cumbria are taken by 132 kV circuits from the two GSPs that run along the lower level land close to the Cumbrian coast. Power is imported to the rest of the Norweb system by a further 12 GSPs (i.e. 14 in total), and imports power from two GSPs in neighbouring PES areas.

Norweb employ a number of connection voltages on their distribution systems. Supplies are taken from NGC at 132 kV and 33 kV and distributed throughout 132 kV, 33 kV, 11 kV and 6.6 kV networks. Parts of the 132 kV network perform the function of transmission circuits carrying power from the large generating stations in Cumbria to the NGC system. In rural areas 11 kV distribution is common but in urban areas, particularly older and densely populated areas such as Manchester, extensive use is made of 6.6 kV networks.

The following summarises key statistics regarding the Norweb distribution system

Area of land covered 12500 sq. km

Approximate number of customers 2,190,000

Norweb Maximum demand (approximate) 4.5 GW

Norweb Minimum demand (approximate) 1.5 GW

Overhead line circuit km 14,636

Underground circuit km 44,709

% of circuits operating at 132 kV 3.2

% of circuits operating at 33 kV 5.3

% of circuits operating at 20 kV <1

% of circuits operating at 11 kV 23.1

% of circuits operating at 6.6 kV 12.6

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4.5.1 Existing Levels of Embedded generationNorweb estimate that they have about 700 MW of embedded generation connected to their system in Cumbria alone, with about 350 MW in the rest of the region. Norweb suggested that there may also be a number of customers who have installed their own small peak lopping units that are not necessarily known to the Norweb distribution business, and that these units are simply seen as a demand reduction. There are a number of large generating stations connected to the Norweb 132 kV system, especially in Cumbria. The Calder Hall, Sellafield (Fellside Power) and Roosecote power stations are subject to central despatch having registered capacities of 192 MW, 179 MW and 229 MW respectively. In total there is 638 MW of such centrally despatched generation plus approximately 348.2 MW of unscheduled generation connected to the Norweb system. Table 4.5.1 summarises by technology the total capacities of generation with individual capacities between 1 MW and 100 MW that are connected to the Norweb system.

Table 4.5.1 Summary of generation capacity by technology in Norweb area

Technology Installed Declared net Capacity (MW)Gas Turbine 104Diesel 83.5CHP 69Wind 27.6Hydro 10.9Biomass 14.8Landfill gas 8.6Waste 15Gas expansion 14.8

Total 348.2

4.5.2 Network Planning StrategiesNorweb are conscious of the need to treat all connection applications in a fair and equitable manner and have procedures that aim to ensure that this is achieved. For each application received a full computer based system study is performed, which includes load flow, short circuit and transient stability studies if appropriate. Transient stability studies are normally only performed for applications that employ synchronous machines and that have a generating capacity of 40 MW or more. Synchronous machines are not normally connected to the Norweb 11 kV network as the fault clearance times that are associated with the protection schemes employed on these networks (Inverse time delay relay with Definite Minimum Time (IDMT)) are such that transient stability is likely to be a problem. Table 4.5.2 summarises the range of voltages that Norweb permit for each system operating voltage.

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Table 4.5.2 Summary of permitted voltage ranges and fluctuation permitted on Norweb distribution system

Nominal system Voltage Permitted range Comments11 kV ± 6% } This is the maximum that can be accepted33 kV ± 6% } although Norweb commented that they would132 kV ± 10% } seek to harmonise their standards with those

} employed by NGC, where appropriate

Voltage fluctuations Between 1% and 3% As per P28 LimitsVoltage change on loss 6% maximum 6% is the maximum that Norweb will permit but aof generation 3% change is desirable limit

Norweb perform computer based short circuit studies in accordance with the principals described in Engineering Recommendation G74. Norweb consider that G74 has inherent margins of safety and that by following the G74 methodology with application of appropriate tolerances the calculated value of short circuit current may be allowed to reach switchgear rated values without compromising the integrity of the system. However, Norweb commented that in their experience the connection of embedded generation generally results in fault levels that are either comfortably within the switchgear rating or in excess of the rating. The issue of an acceptable fault level margin has not proven to be a contentious issue in Norweb’s experience.

4.5.3 The capacity for more embedded generationThe capability of the Norweb distribution network to accept more embedded generation varies considerably across the region.

Since the main function that the 132 kV system performs in Cumbria is that of transmission circuits then the capacity for accepting more embedded generation at 132 kV is influenced by operational considerations, i.e. the extent to which the large power plants in Cumbria are despatched when compared to the thermal capacity of the circuits.

At lower voltage levels the capacity is influenced by thermal and voltage considerations during periods of maximum power flows.

Norweb Views

Information has been obtained in response to a questionnaire and from separate discussions held with Norweb planning engineers. Although the questionnaire had not been fully completed Norweb have subsequently indicated that there is no spare capacity in the 132 kV circuits out of Cumbria and that there are no opportunites to connect new generation capacity at any volatge level in the county. As a consequence, any new generation projects in that area would need to be directly connected to either Harker or Hutton 132 kV substations. Norweb have not been asked to perform generation connection

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studies in other areas that have resulted in such network limitations being identified and as such were not able to have a clear idea of the capacity of the rest of the system to accept additional generation.

During the discussions Norweb suggested, as a rough guide, that generation of between 10 and 20 MW could be accommodated at most 33 kV bulk supply points, up to 5 MW could be connected to most 11 kV primary substations and up to 2 MW at most 6.6 kV primary substations. The amount of generation that can be connected will generally decrease with distance from the primary substation as conductor loading, voltage regulation and voltage control become limiting factors. Norweb indicated that Harker and Hutton grid supply points may each be able to accept up to a total of 100 MW of new generation, providing a connection is made directly to the substations.

Norweb is not aware of any areas within the network where the connection of generation would be positively beneficial to the operation of the system, or provide security levels as required by Engineering Recommendation P2/5. However, there may be benefits in the future if novel contracts guaranteeing generator output could be struck, and the issues of the security of such generation could be proven to satisfy the requirements of P2/5. Such arrangements may defer system reinforcement needs.However, Norweb expressed doubts as to whether generators would wish to enter into such contracts.

Quantitative assessment

Based on Norweb’s views regarding the capability of their distribution networks to accept new embedded generation we have performed some simplified analysis in order to estimate the total generation capacity that may be connected in the North West. In our analysis we estimated that on average it should be possible to connect the following amounts to different types of distribution system:-

System voltage

Location 6.6 kV 11 kV 33 kV

Rural 2 MW 10 MW

Urban 2 MW 5 MW 20 MW

We have further estimated that approximately 50% of the Norweb distribution networks may be classified as rural and 50% classified as urban for the purposes of our analysis. On the basis that there are only limited opportunities to connect new generation in Cumbria and that generation connecting at 33 kV may reduce the capability of a lower voltage system to accept new generation, a crude estimate of the generation that may be connected to the Norweb distribution system is in the order of 1.5 GW, with approximately 500 MW of this being connected in rural areas and 1 GW in urban areas. However, these estimates assume that it is possible to locate a large number of ideally sized generators such that they minimise the effect on the distribution system and do not interact with each other. In practice this is unlikely to be achievable, and so we estimate that the Norweb distribution system may be able to accept about 620 MW of new embedded generation, with approximately

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200 MW connecting in rural areas and 420 MW connecting in urban areas. However, at this level of generation penetration difficulties with voltage and frequency control may be experienced at times of light load and procedures would be required to allow generation to be constrained off. The details of the derivation of the estimated ability of the Norweb network to accept new generation are included in Appendix B of this report.

Limiting factors for the connection of new generationIn Cumbria the thermal capacity of the circuits out of the county are fully utilised to export the power from the existing generation in the county. Norweb have already reconductored and reprofiled the lines so that they are using the largest feasible conductor size at 132 kV at its highest operating temperature. This means that there is effectively no scope for connecting new generation until new circuits are installed between Cumbria and Lancashire or some of the existing generation capacity is removed.Both of the these options are unlikely to be realised in the near future. In general, Norweb expect to have difficulties obtaining permission to install new overhead lines in Cumbria, particularly for 132 kV lines.

In other rural areas voltage regulation is thought to be the main limiting factor to the connection of new embedded generation. In urban areas short circuit ratings of existing equipment is considered to be the main limiting factor.

4.5.4 Experience of Norweb in dealing with Embedded generationNorweb advised that the presence of embedded generators did have a significant impact on their day to day operations as the generator must gain Norweb’s permission before synchronising, which adds to the operational administration and control. With regard to the effect of renewable generators on the quality of supply, Norweb have tended to connect wind farms to electrically stiff points in their network and have not experienced any voltage fluctuation or waveform distortion problems.

4.6 Merseyside and North Wales - ManwebThe electrical distribution networks in Merseyside, North Wales and parts of Cheshire, greater Manchester, Shropshire and Staffordshire are owned and operated by Manweb. The Manweb system has a mixture of urban networks that supply the high load density areas in Liverpool, Warrington,St Helens, Crewe and Wrexham and rural networks that supply the lower density communities in mid Cheshire, the Dee Valley, Clwyd, Gwynedd and Aberystwyth. There are sixteen grid supply points that supply the Manweb system, twelve of which are within the Manweb area and four of which are shared with neighbouring PES companies. Supplies are taken from NGC at 132 kV and distributed through the 132 kV network to bulk supply points and are then distributed through 33 kV, 11 kV or 6.6 kV networks. Major generating stations in the Manweb area that are connected to the NGC transmission system include Ffestiniog, Dinorwig, Wylfa, Connahs Quay, Deeside and Fiddles Ferry. There is a predominant power flow from west to east on the NGC network in this area, however there is also some through power flowing in Manweb’s 132 kV distribution system.

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Manweb is unique among the provincial PESs in that they operate their 33 kV and 11 kV systems as interconnected mesh networks, which enables them to provide a more secure supply to their customers but tends to result in higher fault levels than would be present if the system were operated radially. The protection and control requirements associated with interconnected system are inevitably more complex than those for a radial system, which may affect the design and cost of connection to such a system. However, it is not thought that this would be significant factor in the development of embedded generation in the Manweb area. The following summarises some key statistics for the Manweb system:

Area of land covered 12,200 sq. km

Approximate number of customers 1,371,000

Manweb Maximum demand (approximate) 4.02 GW

Manweb Minimum demand (approximate) 1.4 GW

Overhead line circuit km 21,440

Underground circuit km 23,461

% of circuits operating at 132 kV 3.5

% of circuits operating at 33 kV 7.4

% of circuits operating at 22 kV <1

% of circuits operating at 11 kV 40

% of circuits operating at 6.6 kV 3.9

4.6.1 Existing Levels of Embedded generationManweb have advised that they have approximately 712 MW of embedded generation connected to their system. The embedded generators consist mainly of combined heat and power plants, wind energy schemes and hydro generators with smaller amounts of biomass, landfill gas and waste to heat generators. The high level of CHP schemes reflects the industrial nature of loads in the Merseyside, west Lancashire and Wirral areas, whereas the relatively high level of wind generation reflects the opportunities for the development of such generation in north Wales. The majority of generation schemes are connected at 33 kV, although over 100 MW of CHP generation is connected at 11 kV. Table 4.6.1 summarises the generation in the Manweb area

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Table 4.6.1 Summary of generation capacity by technology in Manweb area

Technology Installed Declared net Capacity (MW)CHP 395.5 *Wind 126.7Hydro 170.5Bio-mass 3.1Landfill gas 11.5Waste to heat 4.8

Total 712.1

* Note Manweb advised that this figure may include some discrepancies, depending on the information provided by the

customer. In some cases the information recorded may detail the power that may be exported to the Manweb system, whereas

in other cases the information may include the full generation capacity on the site (including those of standby generators).

However, for the purposes of this study it is assumed that the information is accurate.

4.6.2 Network Planning StrategiesManweb are conscious of the need to treat all connection applications in a fair and equitable manner and have procedures that aim to ensure that this is achieved. For each formal application received a computer based system study is usually performed, which includes load flow and short circuit studies. Transient stability studies are not normally undertaken, but Manweb will advise customers of situations where they consider that transient stability issues may affect the operation of the generation. In such cases Manweb consider that it is the generators responsibility to ensure that the generator can remain stable, as protection will ensure that the Manweb system remains intact.

Short circuit studies are performed in accordance with the principles described in Engineering Recommendation G74. Although Manweb have no formal policy regarding a fault level margin that should be allowed between the switchgear rating and the prospective fault duty, Manweb advised that when an initial assessment of a generation project is performed they would aim to have at least 5% margin, to allow for inaccuracies in data used in the studies. If the initial assessment indicated a margin of less than 5% between the switchgear rating and the prospective duty Manweb would perform a more detailed study and would, in theory, be prepared to allow the prospective fault level to reach the switchgear duty.

Manweb design their system to maintain voltage fluctuations within the limits described in Engineering Recommendation P28, which have a non-linear relationship with fluctuation frequency. However, as a general guide the limits can be more simply defined as a 1 % change in voltage for frequent fluctuations (those with a repetition rate of once every 10 seconds) and a 3% change for infrequent fluctuations (those with a repetition rate in excess of once every 10 minutes). A voltage change of up to 6% on the loss of generation from full load can be accepted.

4.6.3 The capacity for more embedded generationThe capability of the Manweb distribution network to accept more embedded generation varies considerably across the region. In north west Wales the distribution system has a relatively low demand and already has a significant number of generation schemes connected in that area, whereas in the Merseyside and Wirral areas there is a concentration of large industrial consumers that already

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have on site generation. The ability of the Manweb system to accept additional generation is therefore determined by the different issues that are presented by the characteristics of the networks in each geographic area.

Manweb’s ViewsInformation has been obtained in response to a questionnaire and from separate discussions held with Manweb planning engineers. Manweb advised that recent studies have indicated that there are effectively no opportunities to connect new generation in the Aberystwyth area, and that the opportunities in north Wales as a whole are generally very limited. The opportunities are generally limited by the firm thermal capacity of the networks, as the demands in the north west Wales are generally low and have not increased significantly for several years, whereas the capacity of generation connected to the systems has increased. In the industrial and urban areas of Mersyside, the Wirral and Cheshire, Manweb suggest that there may be scope for connecting some new generation but that in many areas this would be limited by fault level considerations. Manweb were unable to provide any indications of general capacities that could be connected as the issues vary so much depending upon where in their network the generation is to be located. The capacity for individual networks to accept new generation are limited to such a degree that each application must be considered individually. Manweb advised that they are often asked to investigate a number of connection options to determine the best combination of connection location, connection voltage and generation capacity hence the suggestion of typical capacities for network types will not be appropriate. Manweb’s view is that the connection of any new generation of significant capacity is likely to require major reinforcements to their distribution system.

Quantitative assessmentWe have performed a simplified analysis to confirm the limited opportunities to connect new generation in the Manweb area. The analysis confirms the high fault levels in the urban and industrial areas and the limited thermal capacity in north Wales during periods of minimum demand. Our analysis suggests that the connection of any new generation in north Wales would probably need to be at 132 kV, which will tend to rule out any generator less than 40-50 MW on economic grounds. Based on information provided by Manweb together with information available from NGC and Offer we have assumed that the following amount of new generation capacity could, in theory, be connected across the whole Manweb distribution system:-

approximately 350 MW at 132 kV, before fault levels are exceeded at 132 kV approximately 110 MW at lower voltages, principally 11 kV before fault levels are exceeded

It may therefore be assumed that it is possible to connect as much as 460 MW of new embedded generation to the Manweb system, assuming that a large number of generators of an appropriate capacity can be connected at suitable locations on the system. In practice this is unlikely to be realised, as technical, economic, and planning considerations will tend to result in a smaller number of generators with the largest possible capacity being connected at a few locations. We expect that the Manweb system may accept a total new generation capacity of about 460 MW, mainly at 132 kV and mainly in urban and industrial areas. The details of the derivation of this estimate are included in Appendix B of this report.

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Limiting factors for the connection of new generationIn north Wales the capacity for connecting new generation is principally limited by the thermal capacity of the distribution network. At times of minimum demand in north Wales, Aberystwyth in particular, the generation capacity on the 33 kV and lower voltage systems exceeds the connected demand and power is exported back through the 132 kV system. At Aberystwyth, no new generation can be accepted unless the thermal capacity of the 132/33 kV transformers and possibly the rating of the 132 kV lines are increased, or unless the generator is prepared to be constrained off at minimum demand. These factors effectively preclude the connection of new NFFO generation schemes in the Aberystwyth area, as NFFO generators can not be constrained in such a way. In other rural areas voltage regulation will be the main factor that limits the connection of new embedded generation schemes. In urban and industrial areas fault levels will be the main limiting factor to the development of new embedded generation schemes, as in many areas there is effectively no spare fault level margin at 33 kV.

4.6.4 Experience of Manweb in dealing with Embedded generationThe Manweb system has operated with a number of embedded generators connected for many years, therefore Manweb have considerable experience in planning and operating their network with such generators in service. Since privatisation the relationships between the generators and Manweb have necessarily changed, in that both the generators and Manweb now operate in a more commercial manner which requires more formal contractual arrangements to be put in place between the generator and the host PES. As more generation is connected with different operating characteristics and employing new technologies Manweb have advised that they encounter new challenges that enable them to increase their experience and incorporate this experience in future work. An example of how such experience may be applied is in improving the accuracy of the initial advice and indicative connection costs they provide to developers. Overall Manweb prefer to discuss the likely connection for a given site with a developer and to identify potential difficulties at an early stage. In the case of NFFO applications this has resulted in a lower number of NFFO applications being formally submitted to Manweb, but fewer of the applications are for connections that are technically unrealisable.

Manweb advised that generally they have not noticed any of the theoretical benefits that are expected to arise from the presence of embedded generation on their system in practice. The theoretical benefits such as reduced losses, deferred system reinforcement or improved system performance are not realised in some cases because it is not in the commercial interest of the generator to enter binding agreements that would enable such benefits to be realised. Manweb have advised that embedded generation has increased their administration requirements and load forecasting errors. Where the embedded generation is from an induction machine it can also have the effect of reducing the system power factor which tends to increase system losses. Manweb are concerned that if embedded generation continues to be developed as forecast then the associated additional communications, administration and load forecasting errors will also increase and that the number of nuisance generation trips will increase, which will have an impact on the quality of supply to Manweb customers. Manweb are keen to encourage discussions and investigations of the technical, commercial and legal issues associated with the large scale development of embedded generation.

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4.7 Yorkshire and Humberside - Yorkshire ElectricityThe Yorkshire Electricity network covers the area from the Pennine uplands in the north west, the coast near Bridlington in the north east, the coast near Saltfleet in the south east and Sheffield in the south west. The Yorkshire Electricity network supplies the major conurbations of Leeds, Bradford, Hull and Doncaster and the industrial areas such as Humberside and Sheffield. This area encompasses the counties of West Yorkshire, Humberside and almost all of South Yorkshire, together with parts of North Yorkshire, Derbyshire, Nottinghamshire, Lincolnshire and Lancashire. The area supplied therefore has a mixture networks designed to meet the characteristics of heavy industrial, urban and rural systems.

The region that Yorkshire Electricity supplies also has a lot of conventional power stations that are connected to the NGC transmission system, such as Drax, Ferrybridge, Eggborough, Keadby, Killingholme and South Humber Bank. The area around the Humber has good access to the main gas and NGC transmission systems and has proven to be a popular location for new gas fired power stations, such as Keadby, Killingholme and South Humber Bank. Yorkshire Electricity is supplied from the NGC transmission system at 21 grid supply points, although there are a further three GSPs that are provided for large customers who take their power directly from the grid. At the GSPs where electricity enters the Yorkshire Electricity system it is transformed to a lower voltage for distribution purposes, mainly to 132 kV but in some areas, particularly in South Yorkshire, to 66 kV or 33 kV. The need for high fault levels to minimise the affect of industrial customers on the quality of the electricity supply led to the introduction of 275/33 kV substations in South Yorkshire, especially in Sheffield.

The following summarises key statistics regarding the Yorkshire Electricity distribution system

Area of land covered 10,700 sq. km

Approximate number of customers 2,060,000

Yorkshire Electricity Maximum demand (approximate) 5.83 GW

Yorkshire Electricity Minimum demand (approximate) 2.00 GW

Overhead line circuit km 15,895

Underground circuit km 38,749

% of circuits operating at 132 kV 2.5

% of circuits operating at 66 kV 2.0

% of circuits operating at 33 kV 4.6

% of circuits operating at 20 kV <1

% of circuits operating at 11 kV 37.1

% of circuits operating at 6.6 kV <1

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4.7.1 Existing Levels of Embedded generationYorkshire Electricity have advised that they have approximately 650 MW of embedded generation connected on their system. The embedded generators consist of diesel generators, combined cycle gas turbines, combined heat and power plants, wind energy schemes, landfill gas generators and waste to heat schemes. The majority of generation schemes are connected at 11 kV and 33 kV with the larger CCGT and CHP schemes connecting to the 132 kV systems. Table 4.7.1 summarises the generation in the YE area

Table 4.7.1 Summary of generation capacity by technology in Yorkshire Electricity area

TechnologyDieselGas TurbineWindLandfill gas, Waste plus CHP

Installed Declared net Capacity (MW)19229549114

Total 650

Note A number of Diesel, Open cycle Gas Turbines generation schemes may also use waste heat from the generator on site,

but have not been classified as CHP plants in the above table.

4.7.2 Network Planning StrategiesYorkshire Electricity are conscious of the need to treat all connection applications in a fair and equitable manner and have adopted procedures that enable this to be achieved. For each application received a full computer based system study is performed, which includes load flow, short circuit and transient stability studies. Table 4.7.2 summarises the range of voltages and voltage fluctuations that Yorkshire Electricity accept on their distribution system.

Table 4.7.2 Summary of permitted voltage ranges and fluctuation permitted on Yorkshire Electricity distribution system

Nominal system Voltage Permitted range Comments11 kV ± 6% } YE will comply with the requirements of33 kV ± 6% } the Electricity Supply Regulations (1988), P28132 kV ± 10% } and other directives as appropriate

Voltage fluctuations Between 1% and 3% } As per P28 LimitsVoltage change on loss of generation

6% }

Yorkshire Electricity perform computer based short circuit studies in accordance with the principals described in Engineering Recommendation G74 and allow a further 5% margin for safety between the calculated value of short circuit current and switchgear rating.

4.7.3 The capacity for more embedded generationThe capability of the Yorkshire Electricity distribution network to accept more embedded generation varies considerably across the region. The degree to which new generation can be accepted is to a large part dependant upon the development of the system to meet the requirements of the system in

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previous years and subsequent changes in the connected demand. The concentration of industrial loads in the Yorkshire Electricity area meant that systems were designed with high fault levels to ensure that the quality of system voltage complies with the required standards, which in some locations may limit the capability of the networks to accept new generation.

Yorkshire Electricity views

Information has been obtained in response to a questionnaire and from separate discussions held with Yorkshire Electricity planning engineers. Yorkshire Electricity advised that they were unable to assess the available spare capacity on their system without performing extensive power system studies. However, they were prepared to discuss the ability of their system to accept generation by area in general terms and comment on the limiting factors in each area. Table 4.7.3 summarises the general ability of the Yorkshire Electricity network to accept additional generation by area. It is also important to note that the connection of generation at 132 kV may result in the available spare capacity at a lower system being reduced due to the increase in system fault levels arising from the connection of the higher voltage generation.

Table 4.7.3 Summary of Yorkshire Electricity network to accept generation by area

Region CommentsNorth Humberside If a number of the large generators that are proposed for connection in this

area proceed then it is unlikely that any generation not already being planned can be accepted on these networks.

South Humberside If a number of the large generators that are proposed for connection in this area proceed then it is unlikely that any generation not already planned can be accepted on these networks

Leeds/Bradford There is scope for connecting suitably sized generation in this area, butYorkshire Electricity advised that in many places there is little fault level margin

Sheffield There is scope for connecting suitably sized generation in this area but the connection of new generation in some locations may cause excessive fault levels at lower voltages.

South Yorkshire There is scope for connecting suitably sized generation in this area, butYorkshire Electricity advised that in many places there is little fault level margin

Pennines There is scope for connecting suitably sized generation in this area, butYorkshire Electricity advised that in many places there is little fault level margin

Quantitative assessment

There are a number of generation schemes that are planned for connection at 132 kV in Humberside that will effectively take all of the spare capacity on these networks. However, the largest of the proposed generators are gas fired stations that will require consents from the government, which under the present moratorium on gas fired generation may not be granted. The 1200 MW Saltend power station, which has been granted consent, is intended to be connected north of Hull and will require the introduction of a 275 kV supply to Saltend South and Saltend North, which shall involve substantial modifications to the existing 132 kV system in that area. The increase in system fault levels at 132 kV resulting from additional generation at this voltage level in the order of 30 MW is likely to cause fault levels on the lower voltage networks to exceed the switchgear ratings, and so there is effectively no

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spare capacity on the 132 kV system to accept additional generation. On this basis it is likely that less than 20 MW could be connected at 33 kV and less than 6 MW at 11 kV.

A similar situation exists in South Humberside where there are plans for new gas turbine generators to be connected at 132 kV near Scunthorpe and increased generating capacity connected near Immingham.

Based on Yorkshire Electricity’s views regarding the capability of their distribution networks to accept new embedded generation we have performed some simplified analysis in order to estimate the total generation capacity that may be connected in their region. In our analysis we estimated that on average it should be possible to connect the following amounts to different types of distribution system:-

System voltage

Location 11 kV 33 kV

Rural 2 MW 10 MW

Urban 10 MW 25 MW

We have further estimated that approximately 55% of the YE distribution networks may be classified as rural and 45% classified as urban for the purposes of our analysis. On this basis a crude estimate of the generation that may theoretically be connected to the Yorkshire Electricity distribution system is in the order of 1.6 GW, with approximately 0.4 GW of this being connected in rural areas and 1.2 GW in urban areas. However, this estimate is based on assumptions that it is possible to locate a large number of ideally sized generators such that they minimise the effect on the distribution system and do not interact with each other. In practice this is unlikely to be achievable, and so we estimate that the Yorkshire Electricity distribution system may in practice be able to accept up to 650 MW of new embedded generation, with approximately 195 MW connecting in rural areas and 455 MW connecting in urban areas. The details of the derivation of this estimate are included in Appendix B.

Limiting factors for the connection of new generationYorkshire Electricity have advised that in many areas their 11 kV networks are operating with fault levels close to the maximum permitted. The situation is such that a generator connecting at 132 kV or 33 kV may require modifications to lower voltage systems but possibly not the system to which it is connecting. This means that there is only very limited scope for connecting new embedded generation at all in the Yorkshire Electricity area unless there is extensive reinforcement of the 11 kV networks. This reinforcement may necessitate a fundamental overhaul of the 11 kV systems as the ratings of switchgear, cables, transformers, overhead lines and the protection systems will need to be reviewed which would both be costly and time consuming. An alternative solution to the high 11 kV fault level problem involves replacing existing 132/11 kV or 33/11 kV transformers with higher impedance transformers, but again this will be costly and it is unlikely that projects with a relatively small generation capacity (less than say 50 MW) could bear the associated costs.

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4.7.4 Experience of Yorkshire Electricity in dealing with Embedded generationYorkshire Electricity indicated that as a distribution company they have not experienced any significant benefits associated with the connection of embedded generators. YE are particularly concerned with increases in distribution system losses arising from the operation of embedded generators and advised that they are developing tools to accurately determine loss levels and those associated with the operation of an individual generator so that the costs of these losses can be correctly allocated. YE also indicated that other issues such as increased load forecasting errors, increased administration and possible increases in customer complaints have an impact on their experience of embedded generation but that the effect of such issues is difficult to quantify.

YE considered that the potential growth of domestic generating units connected to low voltage supplies without their knowledge poses a threat to the future operability of their system.

4.8 West Midlands - Midlands ElectricityThe Midlands Electricity network covers the area from North Staffordshire in the north, Shropshire and Hereford in the west, Gloucestershire in the south, and Birmingham and Worcestershire in the east. The MEB network supplies major conurbations and industrial areas in Birmingham, Wolverhampton, Stoke, Dudley and Walsall and plus the smaller urban areas of Hereford, Gloucester, Banbury and Shrewsbury. The MEB network serves the rural communities along the Welsh border, Gloucestershire and Herefordshire but covers no mountainous regions.

The Midlands Electricity network is supplied from the NGC transmission system at 15 GSPs within its authorised area and from 5 GSPs in neighbouring PES areas. At 14 GSPs within the MEB area the electricity is taken at 132 kV and at one GSP it is taken at 66 kV. The MEB distribution system comprises 132 kV, 66 kV, 33 kV, 11 kV and lower voltage networks.

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The following summarises key statistics regarding the Midlands Electricity distribution system

Area of land covered 13,300 sq. km

Approximate number of customers 2,200,000

Midlands Electricity Maximum demand 5.69 GW

Midlands Electricity Minimum demand (approximate) 2 GW

Overhead line circuit km 25,788

Underground circuit km 37,643

% of circuits operating at 132 kV 2.6

% of circuits operating at 66 kV 1.3

% of circuits operating at 33 kV 3.2

% of circuits operating at 20 kV <1

% of circuits operating at 11 kV 41.8

% of circuits operating at 6.6 kV 1.7

4.8.1 Existing Levels of Embedded generationMidlands Electricity have advised that they have at least 224.4 MW of embedded generation connected to their system. The embedded generators consist of diesel generators, combined cycle gas turbines, combined heat and power plants, wind energy schemes, landfill gas generators and waste to heat schemes. The majority of generation schemes are connected at 11 kV and 33 kV with the larger waste to heat schemes connecting to the 132 kV systems. Table 4.8.1 summarises the generation in the Midlands Electricity area. Two 220 MW nuclear generating units that are dispatched by NGC are connected at 132kV at Oldbury, which is also in the Midlands Electricity area.

Table 4.8.1 Summary of generation capacity by technology in Midlands Electricity area

Technology Installed Declared net Capacity (MW)Diesel 17.6Gas Turbine 22.9Combined Heat and Power 15Wind 0.5Landfill gas 32.3Waste to heat 94.3Others 41.8

Total 224.4

Note A number of Diesel, Open cycle Gas Turbines and Landfill Gas generation schemes may also use waste heat from the

generator on site, but have not been classified as CHP plants in the above table.

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4.8.2 Network Planning StrategiesMidlands Electricity perform a computer based power systems analysis for each generation application received, to investigate system power flows, voltage profiles and short circuit levels. For larger installations (particularly those connected at 132 kV) a transient stability study is also performed. Table 4.8.2 summarises the permitted voltage ranges and fluctuation that may be accepted on the MEB distribution system.

Table 4.8.2 Summary of permitted voltage ranges and fluctuation permitted on MEB distribution system

Nominal system Voltage Permitted range Comments11 kV ± 6% } although this is the maximum tolerated MEB33 kV ± 6% } will attempt to achieve a smaller voltage change132 kV ± 10% } if this is realistic

Voltage fluctuations Between 1% and 3% As per P28 LimitsVoltage change on loss 6% MEB will attempt to achieve a smaller voltageof generation change if this is realistic

Midlands Electricity assess the adequacy of switchgear for each application received and each instance is considered on its own merits. This assessment takes into account the type of circuit breaker, its’ condition, location and the accuracy of the calculation used to determine the prospective switching duty. If necessary, Midlands Electricity would carry out a more detailed assessment to determine the suitability of the switchgear for operation on the system with the proposed generator in service.

4.8.3 The capacity for more embedded generationThe capability of the Midlands Electricity distribution network to accept more embedded generation varies considerably across the region. The degree to which new generation is acceptable is to a large part dependant upon the development of the system to meet the requirements of the system in previous years and subsequent changes in the connected demand. The concentration of industrial loads in the Midlands Electricity area meant that many of their systems were designed with high fault levels to ensure that the quality of system voltage complies with the required standards. In some areas the fault levels are approaching the switchgear ratings, which may limit the ability of the networks to accept new generation.

Midlands Electricity ViewsInformation has been obtained in response to a questionnaire and from separate discussions held with a Midlands Electricity planning engineer. The information provided suggests that there is only limited scope for connecting new generation to the existing Midlands Electricity network. Midlands Electricity advised that there are networks supplied from a number of GSPs where there is effectively no capacity for connecting new generation. Midlands Electricity indicated that other networks in their region have some spare capacity, but were unable to provide information on the actual ability of these networks to accept additional generation without performing further power system analysis. Midlands Electricity were able to advise that the enquiries that they had received for connection of generation to the networks with spare capacity had not caused the available capacity to be exceeded.

Quantitative assessmentBased on the information provided by Midlands Electricity we consider that it may be reasonable to assume that within the areas where Midlands Electricity indicated that there is some spare capacity it

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may be possible to connect between 10 and 20 MW at most 33 kV bulk supply points. We also consider that on average it may be possible to connect up to 5 MW at 11 kV primary substations, with perhaps a total of 100 MW per 132 kV group, depending upon the precise details of the proposed generation. On this basis we estimate that a total of 885 MW of suitably sized generation could be connected at locations across the Midlands Electricity network. However, this is unlikely to be achieved in practice as economic considerations will tend to cause generators with less than ideal capacities to be connected, and the total capacity could be limited due to the interaction between machines. We therefore estimate that a total of 330 MW of new generation could be connected to the Midlands Electricity distribution system. The details of the derivation of this estimate are included in Appendix B.

Limiting factors for the connection of new generationIn the Midlands Electricity region fault levels are the main factor limiting the connection of new embedded generation, particularly in industrial areas. In the areas where Midlands Electricity have indicated that there is no spare capacity, prospective fault levels at 132 kV are close to the switchgear rating, such that the connection of generation at lower voltages may result in the switchgear duty exceeding the switchgear rating. In the Midlands Electricity area a large proportion of the demand is supplied by direct transformation from 132 kV to 11 kV, hence fault levels are also a limiting factor at 11 kV. The Midlands Electricity systems were designed for current carrying capacity and consequently in urban areas fault levels are high compared with switchgear ratings.

4.8.4 Experience of Midlands Electricity in dealing with Embedded generationMidlands Electricity indicated that as a distribution company they have not experienced any significant benefits associated with the connection of embedded generators, but they recognise how they may benefit in the future if embedded generation develops in a suitable way. Midlands Electricity indicated that if there are several installations on the same network it may be possible to treat this as a demand reduction, thereby permitting deferred reinforcement of a higher voltage network. The main drawbacks experienced by Midlands Electricity due to the presence of embedded generation on their network are increases in system fault levels, voltage rise problems and difficulties in determining actual and predicted loads due to varying generation outputs.

4.9 East Midlands - East Midlands ElectricityThe East Midlands Electricity (EME) area encompasses almost all of the counties of Derbyshire, Nottinghamshire, Leicestershire, Lincolnshire and Northamptonshire. The area also includes parts of Buckinghamshire, Bedfordshire, Cambridgeshire, Oxfordshire, Staffordshire, South Yorkshire, Warwickshire and West Midlands. The area has a number of medium sized towns and cities including industrial centres, such as Leicester, Coventry, Nottingham and Derby, smaller towns such as Northampton, Kettering and Grantham, plus the new city of Milton Keynes. The area also serves a large proportion of rural communities, such as those in the low-lying farmlands of Lincolnshire and the hills of the Peak District National Park.

EME takes power from NGCs transmission system at 132 kV at 11 GSPs within its own authorised area and has connections to two GSPs in neighbouring PES areas. The EME distribution system comprises 132 kV, 33 kV, 11 kV, and lower voltage networks and a some 6.6 kV circuits.

The following summarises key statistics regarding the EME distribution system Area of land covered 16,000 sq. km

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Approximate number of customers 2,300,000

East Midlands Electricity Maximum demand (approximate) 5.52 GW

East Midlands Electricity Minimum demand (approximate) 1.93 GW

Overhead line circuit km 24,618

Underground circuit km 43,060

% of circuits operating at 132 kV 3.7

% of circuits operating at 33 kV 7.4

% of circuits operating at 20 kV <1

% of circuits operating at 11 kV 36.9

% of circuits operating at 6.6 kV 1.5

4.9.1 Existing Levels of Embedded generationEME have advised that they have at least 500 MW of embedded generation connected to their system. The embedded generators consist of diesel generators, combined cycle gas turbines, combined heat and power plants, wind energy schemes, landfill gas generators and waste to heat schemes. The majority of generation schemes are connected at 11 kV and 33 kV with the larger waste to heat schemes connecting to the 132 kV systems. Table 4.9.1 summarises the generation in the EME area.

Table 4.9.1 Summary of generation capacity by technology in EME area

TechnologyDieselGas TurbineCombined Heat and Power

Installed Declared net Capacity (MW)25400323

Total 748

Note A number of Diesel, Open cycle Gas Turbines and Landfill Gas generation schemes may also use waste heat from the

generator on site, but have not been classified as CHP plants in the above table.

4.9.2 Network Planning StrategiesEast Midlands Electricity are conscious of the obligations placed on them under the terms of their PES licence and have adopted procedures that ensure that all connections applications are treated in a fair and equitable manner. For each generation connection application that is received by EME a detailed computer based power system study is performed to asses the impact on the distribution system.These studies include load flow, short circuit and transient stability studies, although for most applications to connect generation at 11 kV a transient stability study is not performed. EME perform short circuit studies in accordance with the procedure described in Engineering Recommendation G74, assuming a short circuit contribution from motors in the general load of 1 MVA per MW of connected load. EME have an ongoing programme of monitoring system fault levels, using the ERA fault level recorder, and are confident that the fault level studies performed correlate with the actual system prospective fault levels. As a result of the fault level surveys EME may be prepared to allow the prospective fault level to reach the switchgear duty, although EME advised that this situation has not yet occurred in practice.

EME plan their distribution system so that voltage fluctuations are within the levels specified in Engineering Recommendation P28. As part of the development of their network EME have published

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proposals1 to move towards a network that will comprise of an integrated 11 kV networks overlaid by a 132 kV network, with large sections of the 11 kV system being undergrounded. If this proposal is adopted then the 33 kV system will be progressively phased out leaving the 11 kV system connected directly to the 132 kV system. If the 33 kV network is eliminated then this will have an adverse impact on the cost of connecting certain capacities generation projects (typically between 10 and 30 MW) as they are more likely to require a connection at 132 kV.

4.9.3 The capacity for more embedded generationEME ViewsEME have advised that the capacity for connecting new embedded generation schemes varies across their region. EME have a large number of generator connection applications that are presently being considered and there are also a large number of schemes at an early enquiry stage. The total capacity of these new embedded generation proposals is in excess of 1500 MW and the development of these schemes will have an impact on the opportunities for future developments.

Quantitative assessmentWe have performed a simplified analysis of the ability of the present EME distribution system to accept new embedded generation. This analysis has assumed that on average it should be possible to connect the following amounts of generation to different types of distribution system:-

1 OFFER, “Reviews of Public Electricity Suppliers 1998 to 2000, PES Business Plans, Consultation Paper”, December 1998, Pages 52-53.

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System voltage

Location 11 kV 33 kV

Rural 2 MW 10 MW

Urban 8 MW 25 MW

We have estimated that approximately 60% of the EME networks have a rural characteristic and 40% have an urban characteristic. On this basis a crude estimate of the new generation that could be accepted in theory by the EME distribution system is in the order of 2.7 GW. However, this estimate is based on the premise that it is possible to locate a large number of ideally rated generators across the distribution system so that they do not interact with each other. In practice this is unlikely to be achievable, due to planning restrictions and resource availability, so we estimate that the EME system may be able to accept up to 920 MW of new embedded generation without significant reinforcement. The details of the derivation of this estimate are included in Appendix B.

Limiting factors for the connection of new generationThe limiting factors to the connection of new generation vary across the region and at different voltage levels. In general, the limiting factor in rural areas will be due to thermal capacity and voltage regulation, whilst in urban areas the limiting factor is more likely to be due to fault levels. In the eastern part of the EME region voltage regulation may a problem due to the length of the connections to the Grid Supply Points, even at 132 kV. In the areas around the main industrial and large conurbations of Derby, Coventry and Nottingham fault levels are more likely to be a limiting factor to the connection of new generation.

4.9.4 Experience of East Midlands Electricity in dealing with Embedded generationEME have not experienced any benefits in the operation of their distribution system that can be attributed to the connection of embedded generation. The effect on distribution system losses and quality of supply due to the presence of embedded generation is difficult to assess accurately, particularly the change in losses due to generators connected to 11 kV networks and those with capacities less than 5 MW. As embedded generators do not generally have a secure connection to the EME system it is not appropriate to use these generators to defer system reinforcements. The level of penetration of embedded generation has resulted in increased administration effort for EME, more system control activities and more difficulty in establishing accurate demand forecasts. In order to accommodate embedded generation EME have, when practical, reconfigured their network to reduce system fault levels. This reduces the operational flexibility that EME have over their system and can increase the complexity of switching operations required for maintenance operations.

EME anticipate that the greatest limit to the connection of embedded generation in the future will be the high marginal cost of connecting the new generation as network limits are exceeded. EME are also aware of the potential growth of offshore wind projects off their eastern seaboard. The development of this generation is likely to be constrained by the cost of controlling voltage fluctuations.

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4.10 Norfolk and East Anglia - Eastern ElectricityThe area covered by the Eastern Electricity PES licence incorporates all of the counties of Norfolk, Suffolk and Hertfordshire, most of Cambridgeshire, Essex and Bedfordshire, part of Buckinghamshire, a small part of Oxfordshire and the northern suburbs of Greater London. The area is predominately rural but there are also a wide range of industries served by EE. These industries include car manufacturing around Luton and Dagenham, oil refining on the Thames estuary, and electronic and computing companies in the Cambridge area. Other major load centres in the region include the urban areas of north London, Watford, Norwich and Peterborough, the ports of Felixstowe, Ipswich, Harwich and Tilbury, plus Stansted and Luton airports.

EE take power from the NGC transmission system at 132 kV from 18 GSPs within their own area and 4 in other companies areas. The EE distribution system operates at 132 kV, 33 kV and 11 kV and lower voltage systems, with only a limited amount of 6.6 kV networks being used.

There are a number of embedded generators that are either in operation or proposed in the EE area, as the proximity to London and availability of gas has led to favourable technical and commercial conditions for project development.

The following summarises key statistics regarding the EE distribution systemArea of land covered 20,300 sq. km

Approximate number of customers 3,122,000

Eastern Electricity Maximum demand (approximate) 7.52 GW

Eastern Electricity Minimum demand (approximate) 2.63 GW

Overhead line circuit km 35,591

Underground circuit km 53,095

% of circuits operating at 132 kV 3.0

% of circuits operating at 33 kV 7.2

% of circuits operating at 20 kV <1

% of circuits operating at 11 kV 40.1

% of circuits operating at 6.6 kV <1

4.10.1 Existing Levels of Embedded generationWe understand that Eastern Electricity have at least 493 MW of embedded generation connected to their system. The embedded generators consist of diesel generators, oil burning thermal plants, biomass, waste to heat, gas turbines, combined heat and power plants, and a small capacity of wind energy generation. The majority of generation schemes are connected at 11 kV and 33 kV, although there are proposals for at least one large combined cycle gas turbine project to connect at 132 kV. Table 4.10.1 summarises the generation in the Eastern Electricity area.

Table 4.10.1 Summary of generation capacity by technology in Eastern Electricity area

Technology Installed Declared net Capacity (MW)Diesel 91.4Gas Turbine 50

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Combined Heat and Power 31.6Wind 2.7Oil 144Biomass 65.9Waste to heat 55Landfill gas 52.2

Total 492.80

Note A number of Diesel and Open cycle Gas Turbines and may also use waste heat from the generator on site, but have not

been classified as CHP plants in the above table.

4.10.2 Network Planning StrategiesEastern Electricity are aware of the obligations placed on them by their PES licence and the need to provide a quality supply to their customers. In order to ensure that they can satisfy both of these requirements they have developed a co-ordinated network planing tool that enables the most cost effective connection to be offered to developers of embedded generation projects.

Eastern Electricity plan and design their system to maintain voltage fluctuations within the limits recommended in Engineering Recommendation P28 and to limit the voltage change on a total loss of generation to within 2% at 11 kV and lower voltages, and 10% at higher voltages. For each generation application received a series of power system studies are performed to assess the impact of the proposed generation in terms of load flows, short circuit contribution and, if appropriate, transient stability. Short circuit studies are performed in accordance with the guidelines specified in Engineering Recommendation G74 and Eastern Electricity consider that as this approach accounts for all fault contributions (including motor backfeed) that there is no requirement to allow an additional margin between the prospective duty and rating of switchgear.

4.10.3 The capacity for more embedded generationThe capability of the Eastern Electricity to accept embedded generation will vary to some degree across the area and by different system voltages. From a transmission system viewpoint the Eastern Electricity area is a good location to connect generation, in that it is a good position from which to supply power to the large demands in the London area. This has led to proposals for the development of embedded power stations in the range 50-400 MW in the Eastern area.

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Quantitative assessmentWe have performed a simplified analysis of the ability of the present Eastern Electricity distribution system to accept new embedded generation. This analysis has assumed that on average it should be possible to connect the following amounts of generation to different types of distribution system:-

System voltage

Location 11 kV 33 kV

Rural 2 MW 10 MW

Urban 5 MW 25 MW

We have estimated that approximately 56% of the Eastern Electricity networks have a rural characteristic and 44% have an urban characteristic. On this basis a crude estimate of the new generation that could be accepted in theory by the Eastern Electricity distribution system is in the order of 2.3 GW. However, this estimate is based on the premise that it is possible to locate a large number of ideally rated generators across the distribution system so that they do not interact with each other. In practice this is unlikely to be achievable, due to planning restrictions and resource availability, so we estimate that the Eastern Electricity system may be able to accept up to 910 MW of new embedded generation without significant reinforcement. The details of the derivation of this estimate are included in Appendix B.

Limiting factors for the connection of new generationThe opportunities to connect generation in the relatively sparsely populated areas of Norfolk may be expected to be limited by voltage regulation difficulties whereas around Ipswich, Norwich and London fault levels will tend to be a more onerous consideration. Eastern Electricity advised that in some cases transient stability considerations may require system reinforcement to be performed. In common with other PESs, Eastern Electricity have experienced some difficulties in obtaining permission to construct new overhead lines, which may be a limiting factor to the connection of new generation in the region.

4.10.4 Experience of Eastern Electricity in dealing with Embedded generationAlthough Eastern Electricity have a relatively small amount of embedded generation connected to their system they recognise the benefits and drawbacks that can arise from the development of such generation. Eastern Electricity have absorbed the lessons learned by other PES companies in accommodating generation on the distribution system, but to date have insufficient experience themselves to measure the effect such generation has on their system. The only measurable effect on their operations that Eastern Electricity could comment upon is the increased administration resulting from the presence of generation on their system.

As Eastern Electricity strive to improve the operation of their system they have identified the need for the commercial terms to be available to embedded generators, and incentives that may be required if the Government’s targets for levels of renewable and CHP generation are to be achieved. Eastern Electricity have advised that developing a connection offer to the developer of an embedded generation scheme they make due allowance for the full value of any accrued advantage in terms of thermal loading, delayed reinforcement and any other site specific issues. As Eastern Electricity have no control

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over the export power from the embedded generation connected to their system they cannot use the generation as an alternative to installing distribution network capacity (i.e. new lines and transformers).

4.11 Central London - London ElectricityThe area covered by the London Electricity network covers the whole of central London and large areas of the suburbs. The boundaries of the areas extend to Loughton to the north east, Highgate in the north, Hammersmith to the west, Raynes Park in the south west, Beckenham in the south and Dartford in the south east. This area supplies the highest load densities in Britain. The network is almost entirely urban and mainly comprises cable circuits at each of the supply voltages used by LE. LE take their supplies from the NGC transmission system from 18 GSPs, 12 of which are in their area and 6 in neighbouring PES areas.

The primary networks in the London Electricity area operate at 132 kV, 66 kV, 33 kV and 22 kV, with secondary networks subdivided into those that operate at high voltages of 11 kV and 6.6 kV, and those that operate at low voltage.

The following summarises key statistics regarding the London Electricity distribution system

Area of land covered 665 sq. km

Approximate number of customers 1,969,000

London Electricity Maximum demand 5.02 GW

London Electricity Minimum demand (approximate) 3 GW

Overhead line circuit km 52

Underground circuit km 29,905

% of circuits operating at 132 kV 1.6

% of circuits operating at 66 kV 1.8

% of circuits operating at 33 kV 2.0

% of circuits operating at 22 kV 1

% of circuits operating at 11 kV 21.9

% of circuits operating at 6.6 kV 1.5

4.11.1 Existing Levels of Embedded generationLondon Electricity have advised that they have approximately 268 MW of embedded generation connected to their distribution system, the bulk of which is connected at 11 kV. The majority of the generators connected in the LE area have a relatively small capacity, say less than 5 MW. LE were unable to provide a breakdown of this generation by technology, but indicated that the larger units tend to be CHP plants, small diesels and waste incinerators. We estimate that approximately 140 MW of the embedded generation in the LE area is from CHP plants. The type of generation indicated by LE is

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consistent with the restrictions on the types of generation that could feasibly be connected in the LE authorised area. The generation schemes are generally used by customers in the LE area as a secondary form of supply, in some cases to reduce the cost of their electricity purchasing and in some cases to improve the reliability and security of supply.

4.11.2 Network Planning StrategiesLondon Electricity are aware of the obligations placed upon then under the terms of their PES licence and have adopted procedures accordingly. For each application received for the connection of an embedded generation scheme LE perform load flow and short circuit studies to assess the adequacy of the system to accept this generation. LE have advise that the nature of their system is such that embedded generators are normally located close to a substation and that voltage fluctuations are generally not a problem so that it is normally not necessary to take them into consideration.

LE perform short circuit calculations in accordance with the principals described in G74, although the nature of the loads in London means that it is prudent to assess the contribution from motors in the load on a site by site basis . The networks are planned to operate within the rating of the installed switchgear and do not allow for an additional fault level margin. LE therefore allow new embedded generation projects to increase the system fault level by as much as the available margin, as long as the switchgear rating is not exceeded. However, the high load densities and relatively short cable lengths in central London has resulted in fairly high fault levels there.

LE plan and operate most of their system to the same P2/5 security standard as most other PES companies. However, the very high load densities in the central London area has resulted in a high concentration of buried cables. This has enabled LE to offer to customers in that area an enhanced level of security of supply as an alternative to their standard level of security, at a modest additional cost. This is unlikely to have an impact on the capacity for connecting embedded generation in the area.

4.11.3 The capacity for more embedded generationThe ability of the LE distribution system to accept more embedded generation will vary to some degree across the network. There are specific difficulties associated with performing works in the London area, particularly relating to access to LE facilities and the construction/installation of new equipment, which is expected to increase associated costs. For this reason existing assets are heavily utilised and there are areas, particularly in inner London, where the equipment is operated close to its rating and may therefore be unable to meet the additional requirements imposed by embedded generation. The prospects for the development of new generation projects in the London area may also be limited by the planning difficulties and increased costs associated with performing works in central London.

London Electricity’s ViewLE were unable to advise of the ability of their system to accept new generation capacity in specific terms but indicated that the fault rating of switchgear relative to the network fault level, and the current carrying capacity of the network will be the key factors limiting the connection of new generation. LE agreed that as a general rule the following generation capacities could be expected to be accepted at the connection voltages indicated, although the actual figure for any given network will depend upon site specific considerations:

Generation that could be accepted by system voltage level

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6.6 kV 11 kV 22 kV 33 kV 66 kV 132 kV

2 MW 5 MW 7 MW 10 MW 30 MW 60 MW

Quantitative AssessmentBased on the discussions with LE we have performed a simple analysis to estimate the total amount of generation that could be connected to the LE system. By applying these crude assumptions we estimate that if a sufficient number of suitably sized generators were to be connected at appropriate locations on the LE system then as much as 1.1 GW of new generation may theoretically be connected. However, this estimate is based on assumptions that it is possible to locate a large number of ideally sized generators such that they minimise the effect on the distribution system and do not interact with each other. In practice this is unlikely to be achievable, and so we estimate that up to 390 MW could be expected to be connected in the LE area, although it is likely that the special difficulties facing developers in central London will result in a new generation capacity much lower than this.

Limiting factors for the connection of new generationThe main factor that will limit the connection of new generation in the London Electricity area is expected to be fault levels. There are a number of areas where there is only limited scope for increasing the fault levels at 11 kV or 22 kV, which may result in generation being connected at 33 kV, 66 kV or 132 kV with the associated additional costs.

4.11.4 Experience of London Electricity in dealing with Embedded generationLondon Electricity advised that they have not experienced any operational difficulties associated with the presence of embedded generation on their system, although they do experience increased administration. This administration is associated both with the connection of the scheme and the need to maintain comprehensive databases for the generators in their area. LE expected that the presence of embedded generation on the system would tend to reduce the system losses, as the demand profile in London is such that there is only a relatively small difference between the maximum and minimum demand for a given year, but advised that this could not readily be quantified without the benefit of detailed system analysis. LE also expected that there would be some benefit in terms of deferred system reinforcement and improved system performance, but again that this would be difficult to quantify without detailed analysis.

Whilst LE recognise the benefits that may be gained by using embedded generators to secure supplies or to defer system reinforcement they would require the generator to enter a binding contractual arrangement where the generator guarantees its availability at designated times. LE have always been prepared to offer such terms and under the 1998 trading arrangements recognise that there are now more incentives for embedded generators to enter such agreements. In LE’s experience generators have been reluctant to enter binding Availability Agreements and as such the full potential benefits that may arise from embedded generation are not being recognised. This reluctance is probably aggravated by the fact that most of the generators are presently used for supply back-up/ reliability purposes, rather than for electricity trading.

4.12 South East England - SEEBOARDThe geographic area covered by SEEBOARD’s PES licence extends into south London in the north, to the Sussex coast to the south, and from the Kent coast in the east to beyond Worthing and Guilford in

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the west. The area includes the counties of East Sussex, almost all of Kent and most of Surrey and West Sussex. Although there are a large number of urban systems in the SEEBOARD area, such as south London, Croydon, Kingston upon Thames, Maidstone, Brighton, Ashford and Crawley there are also substantial rural areas in the north and south Downs and in coastal areas.

SEEBOARD take their supplies from the NGC transmission system at 132 kV from 12 GSPs within their own authorised area and from one GSP in the LE area. The SEEBOARD distribution network operates at 132 kV, 33 kV, 11 kV, 6.6 kV and lower voltages.

The following summarises key statistics regarding the SEEBOARD distribution system

Area of land covered 8,200 sq. km

Approximate number of customers 2,000,000

SEEBOARD Maximum demand (approximate) 4.37 GW

SEEBOARD Minimum demand (approximate) 1.53 GW

Overhead line circuit km 12,665

Underground circuit km 32,247

% of circuits operating at 132 kV 2.9

% of circuits operating at 33 kV 5.3

% of circuits operating at 11 kV 31.1

% of circuits operating at 6.6 kV 4.4

4.12.1 Existing Levels of Embedded generationWe understand that there is approximately 250 MW of embedded generation in the SEEBOARD area, of which approximately 16 MW if from diesel generation, 204 MW from CHP plants, 1 MW from wind turbines and the remainder from non-CHP gas turbine generation.

4.12.2 Network Planning StrategiesSEEBOARD are aware of the obligations placed on them by the terms of their PES licence and have adopted procedures in order to ensure that these obligations are met. A full computer based power system analysis is performed to assess the impact that proposed generation schemes with a capacity greater than 1 MW are likely to have on the SEEBOARD distribution system. Generators with a capacity less than 1 MW are generally connected without a full computer based analysis being performed.

SEEBOARD design and operate their distribution system so that it complies with the statutory requirements of the Grid Code, the Distribution Code and relevant Regulations. SEEBOARD treat each generation connection application on its individual merits and therefore do not prescribe a set of planning standards any stricter than the statutory requirements. SEEBOARD therefore do not prescribe a minimum fault level margin to be maintained between the system prospective fault level and the

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switchgear duty as they consider the relevant circumstances for each application. SEEBOARD strive to achieve the most cost effective connection arrangement for each application they receive and therefore using skilled engineers to design a connection that meets the requirements of both the applicant, SEEBOARD and other users of their system.

4.12.3 The capacity for more embedded generationThe capability of the SEEBOARD network to accommodate new embedded generation varies across the region according to both the type of generation to be connected and the nature of the distribution system in that area.

SEEBOARD’s viewSEEBOARD have advised that they have been able to offer connections to embedded generators in the majority of areas within their region, although in some cases this has indicated the need for costly system reinforcement. Generation from sources such as wind and tidal energy have proven difficult to connect due to the potential fluctuating nature of their output, whereas conventional fossil fuelled energy sources, CHP plants and waste to heat schemes have generally been easier to accommodate. SEEBOARD are aware that a number of areas on their system would probably be able to accept generation of a suitable type and rating, and SEEBOARD are pleased to welcome applications from developers of such generation projects in these areas.

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Quantitative AssessmentWe have performed a simplified analysis based of the ability of the SEEBOARD network to accept new embedded generation. This analysis is on the assumption that on average it should be possible to connect the following amounts of generation to different types of distribution system:

System voltage

Location 11 kV 33 kV

Rural 2 MW 10 MW

Urban 8 MW 20 MW

We have estimated that approximately 42% of the SEEBOARD networks have a rural characteristic and 58% have an urban characteristic. On this basis a crude estimate of the new generation that could be accepted in theory by the SEEBOARD distribution system is in the order of 1.7 GW. However, this estimate is based on the premise that it is possible to locate a large number of ideally rated generators across the distribution system so that they do not interact with each other. In practice this is unlikely to be achievable, due to planning restrictions and resource availability, so we estimate that the SEEBOARD system may be able to accept up to 710 MW of new embedded generation without significant reinforcement. The details of the derivation of this estimate are included in Appendix B.

Limiting factors for the connection of new generationThe limiting factor to the connection of new generation to the SEEBOARD distribution system in urban areas is likely to be those of system fault levels and in rural areas those of voltage regulation. The connection of large amounts of embedded generation at 33 kV and 11 kV that cause power to be exported from these systems may cause problems with the operation of automatic tapchangers and not all of the tapchangers installed on the system will be suitable for accepting reverse power flows.

4.12.4 Experience of SEEBORD in dealing with Embedded generationSEEBOARD have a positive attitude to accepting embedded generation onto their system, particularly generation that is able to offer some degree of security (e.g. by using 2 x 50% or 3 x 33% units rather than a single generator). SEEBOARD treat each application on its merits in order to ensure that they can offer the best connection possible to the developer. SEEBOARD consider that the commercial issue are the principal limiting factor to the connection of embedded generation as technical difficulties can be overcome, but at a cost.

The SEEBOARD system employs a large number of auto-reclose schemes, some of which have an operation time in the order of 1 sec. SEEBOARD are concerned that the connection of embedded generation presents the risk of an auto-recloser closing onto a line energised by the generator, which is likely to be out of phase with the rest of the system. SEEBOARD are presently investigating this matter and the protection schemes that can best satisfy the requirements of the generator whilst meeting the quality of supply targets set for SEEBOARD.

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4.13 Southern England - Southern ElectricThe area covered by Southern Electric’s PES licence extends from north Oxfordshire to the south coast, including the Isle of White, and from east Somerset (including Yeovil and Frome) to west London (including Hounslow and Ealing). The area includes urban areas, such as west London, Slough, Reading, Oxford, Swindon, Poole, Bournemouth, Southampton, Portsmouth and Basingstoke, plus large rural areas such as those in Dorset, the Cotswolds, Salisbury Plain and the Hampshire Downs. The industrial loads in the area are generally those associate with small to medium sized commercial and light industrial businesses that are involved in manufacturing, computing and services.

Southern Electric take their supplies from the NGC transmission system at 132 kV from 14 GSPs in their own authorised areas and from 5 in neighbouring PES areas. Southern Electric operate their distribution networks at 132 kV, 33 kV, 22 kV, 11 kV, and lower voltages, plus there are a limited number of 66 kV circuits.

The following summarises key statistics regarding the Southern Electric distribution system

Area of land covered 16,900 sq. km

Approximate number of customers 2,650,000

Southern Electric Maximum demand (approximate) 6.24 GW

Southern Electric Minimum demand (approximate) 2.2 GW

Overhead line circuit km 28,870

Underground circuit km 43,375

% of circuits operating at 132 kV 3.3

% of circuits operating at 66 kV 0.3

% of circuits operating at 33 kV 6.4

% of circuits operating at 20 kV <1

% of circuits operating at 11 kV 36.6

% of circuits operating at 6.6 kV 2.3

4.13.1 Existing Levels of Embedded generationSouthern Electric did not feel it appropriate to advise of either the level of embedded generation on their system or to indicate the connection voltages or technologies employed by this generation. Southern Electric advised that information had been provided by their customers, and that permission would need to be sought from those customers before passing such information on to Merz and McLellan.At the time of privatisation it was estimated that their was 250 MW of embedded generation on the Southern Electric system, with a further 70 MW of embedded generation forecast. The NGC Seven Year Statement for 1998 indicates that there is 342 MW of independent generating plant embedded in the Southern Electric system, and that there is a further 140 MW of generation that is subject to central despatch. The total amount of generation connected to the Southern Electric network is therefore expected to be in excess of 482 MW. We estimate that this generation will comprise of approximately

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260 MW from CHP plants, 22 MW from diesel generators, less than 1 MW from wind energy, 88 MW from open cycle gas turbines, and the remaining capacity made up from CCGT generators.

4.13.2 Network Planning StrategiesSouthern Electric are conscious of their obligations under their PES licence, including the requirement to treat all connection applications in a fair an equitable manner. For each application received load flow and short circuit studies are performed.

Southern Electric advised that they treat each application individually and therefore, apart from the statutory limits for voltage fluctuations (Engineering Recommendation P28) and the Electricity Regulations 1988, Southern Electric have no overall guidelines for assessing connection applications. The overall magnitude of voltage changes that can be accepted depends upon the configuration of the network and the requirements of customers connected. Southern Electric therefore leave the assessment of the suitability of a proposed connection to the judgement of the responsible engineer. Southern Electric do not specify a minimum margin for safety between the calculated value of short circuit current and switchgear rating.

4.13.3 Limiting factors for the connection of new generationThe capability of the Southern Electric distribution network to accept more embedded generation varies considerably across the region. The degree to which new generation may be accepted is to a large part dependant upon the development of the system to meet the load requirements of the system in previous years and subsequent changes in the connected demand.

Southern Electric’s viewsInformation has been obtained in response to a questionnaire and from separate discussions held with a Southern Electric planning engineer. Southern Electric advised that there are a number of factors that affect the connection of new generation in their area and these are dependant upon the nature of the generation to be connected and also the connection point. Southern Electric agreed that the following levels of generation could reasonably be expected to be accepted by different networks in their area.

System voltage

Location 11 kV 33 kV 132 kV

Rural 2 MW 15 MW 50 MW

Urban 10 MW 20 MW 50 MW

Quantitative analysisBased on the discussions with Southern Electric we have performed a simple analysis to estimate the total amount of generation that could be connected to the Southern Electric system. We have assumed that approximately 50% of the Southern Electric system could be classified as having a rural characteristic and 50% an urban characteristic. Based on these crude assumptions we estimate that if a sufficient number of suitably sized generator were to be connected at appropriate locations on the Southern Electric system then as much as 3.1 GW of new generation could be connected. However, this is unlikely to be realised in practice and it is more likely that about 1.27 GW could be expected to be accepted in the Southern Electric area, with approximately 350 MW connecting in rural areas and

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920 MW connecting in urban areas. The details of the derivation of this estimate are included in Appendix B.

Limiting factors to the connection of new generationIn rural areas the major difficulties are normally those associated with voltage regulation, although for connections close to primary substations short circuit levels may also be a problem. In urban areas fault levels are generally the main concern but in certain locations voltage changes may be a significant factor.

4.13.4 Experience of Southern Electric in dealing with Embedded generationSouthern Electric have noted both benefits and drawbacks from having embedded generation on their system. The benefits have included reduced system losses and improved voltage profiles. The major drawbacks that Southern Electric have experienced is load forecasting difficulties, as changes in output from the embedded generators will need to be supplied from an alternative source.

4.14 South Wales - SWALECThe area covered by SWALEC’s PES licence extends from central Powys in the north, to the Bristol Channel in the south, and from the eastern border of Gwent (plus a small part of Gloucestershire) in the east to the Dyfed coast in the west. This area can be considered in three areas that have different geographic and demographic characteristics. The coastal belt between Newport and Llanelli includes the major towns and cities in the SWALEC area, Newport, Cardiff and Swansea. To the north of this coastal belt is the valleys region where most of the South Wales mining industry was developed. The remainder of the area is mainly rural with a combination of sparsely populated upland areas and coastal regions. In this third area the main commercial activities are those related to farming, apart from the Milford Haven area where there are is a significant petrochemical presence.

SWALEC obtain their supplies from the NGC transmission system from 9 GSPs in their own authorised area, generally at 132 kV, but also at 66 kV and 33 kV. The SWALEC distribution network operates at 132 kV, 66 kV, 33 kV, 11 kV and lower voltages, although the extent of the 66 kV network is limited mainly to central Wales.

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The following summarises key statistics regarding the SWALEC distribution system

Area of land covered 11,800 sq. km

Approximate number of customers 970,000

SWALEC Maximum demand 2.74 GW

SWALEC Minimum demand (approximate) 0.96 GW

Overhead line circuit km 18,621

Underground circuit km 13,514

% of circuits operating at 132 kV 4.2

% of circuits operating at 66 kV 1.3

% of circuits operating at 33 kV 6

% of circuits operating at 11 kV 52.9

% of circuits operating at 6.6 kV <1

4.14.1 Existing Levels of Embedded generationThere is approximately 582 MW of embedded generation presently connected to the SWALEC distribution system. There are a relatively large number of generators that have an individual generating capacity less than 100 MW, plus there is a large 240 MW combined cycle power station that will be centrally despatched by NGC that is planned for connection to the 132 kV close to Barry. The location signals provided by NGC to encourage the connection of new generation projects in South Wales has lead to a significant number of developers showing an interest in connecting gas turbines to the SWALEC network. However, it is not clear as to how many of these schemes will be developed given the present moratorium on consents for gas fired generation. Table 4.14.1 summaries the capacities of generators with an individual capacity of less than 100 MW that are connected to the SWALEC distribution system.

Table 4.14.1 Summary of embedded generation with capacity of less than 100 MW by technology

Technology Installed capacity MWDiesel 3Open Cycle Gas Turbine 0Close Cycle Gas Turbine 34Combine Heat & Power 244.3Wind 24.5Hydro 7.5Biomass 0.4Landfill gas 7.4Waste to heat 0others 20.8Total 341.9

Note A number of Diesel, Open cycle Gas Turbines and Landfill Gas generation schemes may also use waste heat from the

generator on site, but have not been classified as CHP plants in the above table.

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4.14.2 Network Planning StrategiesSWALEC are fully aware of the obligations placed on them under the terms of their PES licence to be non-discriminatory in their analysis of applications to connect to their system. SWALEC are also very aware of the commercial sensitivities of generation projects and the need for confidentiality to maintained, and the systems employed for the processing of connection applications are designed to meet their licence obligations. SWALEC perform a computer based power systems analysis for each generation application received, to investigate system power flows, voltage profiles and short circuit levels. In general, transient stability studies are not performed, but if the size of the proposed generation is such that stability is considered to be a concern a one-off arrangement would be made to investigate this.

Table 4.14.2 summarises the range of voltages and voltage fluctuations that are permitted by SWALEC when considering a connection application.

Table 4.14.2 Summary of permitted voltage ranges and fluctuation permitted on SWALEC distribution systemNominal system Voltage Permitted range Comments11 kV ± 6% } SWALEC will comply with the requirements of33 kV ± 6% } the Electricity Supply Regulations (1988), P28132 kV ± 10% } and other directives as appropriate

Voltage fluctuations Between 1 and 3 % } As per P28 LimitsVoltage change on loss of generation

As per P28 limits

SWALEC perform computer based short circuit studies in accordance with Engineering Recommendation G74. One of the key assumptions that is made in Engineering Recommendation G74 relates to the contribution to the fault current from induction motors in the load. G74 suggests a value for the typical contribution from induction motors in the general load. SWALEC are aware that in some areas, particularly areas with a large number of industrial loads, the G74 value for motor contribution may be too low and in other areas, say more rural areas, the estimated value may be too great. Such uncertainties are compensated for in SWALEC calculations by introducing an additional margin of up to 5% as appropriate over and above their normal 5% margin between calculated fault levels and switchgear ratings. The actual fault margin level will be dependant upon the confidence in the value of induction motor infeed from industrial customers, the position on the network, and the type of plant to be connected etc.

4.14.3 The capacity for more embedded generationThe capability of the SWALEC distribution network to accept more embedded generation varies considerably across the region. The degree to which new generation may be accepted is to a large part dependant upon the development of the system to meet the load requirements of the system in previous years and subsequent changes in the connected demand. The concentration of industrial loads in the coastal belt between Newport and Llanelli meant that many of their systems were generally designed with high fault levels to ensure that the quality of system voltage complies with the required standards. This has the effect of limiting the capacity for more generation in the coastal belt area.

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SWALEC’s viewsInformation has been obtained in response to a questionnaire and from separate discussions held with SWALEC planning engineers. SWALEC indicated that due to the dynamic nature of the distribution network and the site specific nature of generation connection studies it would be very difficult to determine the scope for connecting new embedded generation on the SWALEC system without performing extensive power systems analysis. However, SWALEC were prepared to talk in general terms about the ability of the networks to accept new generation in different areas and to state what the limiting factor is likely to be in each case. In West Wales, the location of the generator site relative to the source substation would be critical to the amount of generation that could be connected. If a direct connection is made to an 11 kV substation then it may be possible to connect between 2 and 3 MW of new generation. In more urban areas there is only limited scope for connecting generation due to fault level limitations, and so in areas such as Cardiff and Aberthaw it may only be possible to connect a maximum of 1 MW at 11 kV.

Quantitative analysisBased on the estimates provided by SWALEC we have assumed that on average the distribution system will be able to accept the following amounts of new generation, providing that suitably sized generators are located at appropriate locations on the networks:

System voltage

Location 11 kV 33 kV

Rural 3 MW 10 MW

Urban 1 MW 20 MW

In addition it may be possible to connect generation to a 66 kV or a 132 kV circuit, but it is expected that this generation would take place instead of generation on a lower voltage system. We have assumed that approximately 80% of the SWALEC system could be classified as having a rural characteristic. Based on these crude assumptions we estimate that if a sufficient number of suitably sized generator were to be connected at appropriate locations on the SWALEC system then as much as 601 MW of new generation could be connected in theory. However, this is unlikely to be realised in practice and it is more likely that about 210 MW could be expected to be accommodated in the SWALEC area. The details of the derivation of this estimate are included in Appendix B.

Limiting factors for the connection of new generationThe factors limiting new generation in South Wales are different in each geographical area. In the rural West Wales a large number of the supplies are only single phase, and it will therefore be necessary to install additional infrastructure to connect a generator. Where there are three phase supplies in West Wales voltage control is the main limiting factor. The feeders in this area are relatively lightly loaded and the circuit lengths relatively long, so the introduction of generation may need to be integrated into the system voltage control schemes, which can generally be best achieved at a source/primary substation.In the valley area the thermal capacity of the 66 kV system is a significant factor that limits the connection of new generation. This problem is due to a number of successful schemes that were awarded contracts under NFFO3 and NFFO4 for which capacity has been allocated which have not yet been connected. It is therefore possible that if these schemes are abandoned that the scope for connecting generation in this area could be increased. In urban areas fault level margins are the limiting factor and consequently it is unlikely that there could be a significant increase in generation connected at 11 kV or 33 kV in the Cardiff and Aberthaw areas unless the system is suitably reinforced.

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4.14.4 Experience of SWALEC in dealing with Embedded generationSWALEC indicated that although they have a significant number of embedded generators connected to their distribution system, as a distribution business they have not yet obtained any measurable benefits in terms of reduced system losses, deferred system reinforcement or improved network performance. SWALEC advised that there had been a number of voltage complaints from customers connected at low voltage, however these complaints are from generators experiencing “engine” problems. In general, embedded generation on the SWALEC system has resulted in increased operating and maintenance difficulties; increased system fault levels make system operation more difficult and complex; management of the system voltage profile is more onerous in order to compensate for the wide “swing” in voltages between steady state and loss of generation. Other difficulties experienced by SWALEC include load forecasting difficulties, as it becomes increasingly difficult to establish the true system loads, planning for system outages as this requires the co-operation of the generators and gaining access to the substations within the generation site. In terms of system planning, the extent to which generation applications will result in firm projects is unknown, so that SWALEC planning engineers have to make a judgement on the amount of generation to be taken into account in their network plans. This uncertainty is further aggravated by the reduction in operational flexibility of the system as the infrastructure was designed to distribute power to customers, rather than accepting power from generators. SWALEC deal with a large number of generator application, which require a large technical input from design engineers and this diverts these engineers from other work.

4.15 South West England - SWEBThe electrical distribution networks in the south west peninsular to the south of and including Bristol and to the west of Yeovil are owned and operated by SWEB. The SWEB system has a mixture of urban networks that supply the high load density areas in Bristol, and rural networks that supply the lower density communities in Cornwall, Devon and Somerset. SWEB have an extensive 132 kV network which is overlaid by NGCs 400 kV transmission system from Hinkley Point (on the Somerset coast) and Axminster (towards the south coast) and west to Taunton, Exeter, and Indian Queens at the furthest extent of the NGC system in Cornwall. The 132 kV networks are not fully interconnected as there is one 132 kV group of circuits extending from Bristol down to Taunton, a second that connects Exeter, Indian Queens, and other substations towards Lands End and Barnstaple, and a third that extends east from Axminster into Southern Electric’s network.

SWEB take their supply from the NGC transmission system from nine GSPs that are within their own authorised area and from two GSPs that are in neighbouring PES areas. The SWEB distribution system operates at 132 kV, 33 kV, 11 kV and lower voltages.

The SWEB region is a net importer of power and as such has become one of the most favourable areas in the UK for the development of new generation projects. As a consequence there are a number of power stations that are either being developed or planned at the moment in the SWEB area that may reduce the scope for future growth of embedded generation in this region.

The following summarises key statistics regarding the SWEB distribution system

Page4.56

Area of land covered 14,400 sq. km

Approximate number of customers 1,316,000

SWEB Maximum demand 3.07 GW

SWEB Minimum demand (approximate) 1.07 GW

Overhead line circuit km 29,205

Underground circuit km 18,612

% of circuits operating at 132 kV 3.2

% of circuits operating at 33 kV 8.1

% of circuits operating at 11 kV 48.9

% of circuits operating at 6.6 kV 0.4

4.15.1 Existing Levels of Embedded generationSWEB have indicated that they presently have 145 MW of embedded generation connected in their area, 135 MW of which is connected at 11 kV and 10 MW of which is connected at 33 kV. It is thought that the diesel generators that are present in the SWEB area are used mainly for peak lopping or demand reduction purposes by large industrial customers in order to minimise the electricity charges during periods of peak electrical demand (i.e. during Triad pool settlement periods).

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Table 4.15.1 Summary of embedded generation with capacity of less than 100 MW by technology

Technology Installed Declared net Capacity (MW)Diesel 72Open Cycle Gas Turbine 42Combined Cycle Gas Turbine 0CHP 1Wind 13Hydro 6Bio-mass 4Landfill gas 7

Total 145

Note A number of Diesel, Open cycle Gas Turbines and Landfill Gas generation schemes may also use waste heat from the

generator on site, but have not been classified as CHP plants in the above table.

4.15.2 Network Planning StrategiesSWEB recognise the importance of treating all generation applications on a fair and equal basis. Computer based studies are used to assess the impact on system load flows, short circuit levels, system stability and protection. Table 4.15.2 summarises the criteria SWEB apply when assessing the impact of new generators on their distribution system

Table 4.15.2 Summary of permitted voltage ranges and fluctuation permitted on SWEB distribution systemNominal system Voltage Permitted range Comments11 kV ± 6% }33 kV ± 6% } As per Electricity Supply Regulations132 kV ± 10% }

Voltage fluctuations

Voltage change on loss of generation

1% frequent1% infrequent6%

This is a slightly stricter requirement than that suggested in ER P28

SWEB perform short circuit studies in accordance with the procedures outlined in Engineering Recommendation G74 and allow a further margin for safety between the calculated value of short circuit current and switchgear rating. As much of the switchgear that is subject to fault level limitation is at NGC safety managed sites, SWEB have to fall in line with NGC’s margin for safety, which is currently 2%.

4.15.3 The capacity for more embedded generationThe capability of the SWEB distribution network to accept more embedded generation varies considerably across the region. The degree to which new generation may be accepted is to a large part dependant upon the development of the system to meet the load requirements of the system in previous years and subsequent changes in the connected demand and generation.

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SWEB’s View

Information has been obtained in response to a questionnaire and from separate discussions held with SWEB planning engineers. Table 4.15.3 presents the spare capacity that SWEB indicated may be available on their network if suitable generation application schemes are received. The incentives provided in terms of the use of system charges that generator in the South West are expected to pay are such that SWEB have recently received applications to connect about 600 MW of generation to their 132 kV network, 100 MW at 33 kV, 30 MW at 11 kV and 4 MW at low voltage. These figures do not include over 400 MW of applications for the connection of renewable energy projects under NFFO5. These figures demonstrate the commercial interest in developing embedded generation schemes in the South West and it is possible that if the schemes that have already approached SWEB are developed then this could take up all of the capacity indicated. There are also plans for the connection of larger generating stations in the Plymouth and Bristol areas which will increase the overall system fault levels and, if connected, could therefore reduce the spare capacities indicated.

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Table 4.15.3 Indicative spare capacity on the SWEB network

Region Voltage Capacity (MW) CommentsIron Acton 132 0 Fault level limitation

33 30Seabank 132 0 Fault level limitation

33 20Bridgwater 132 50 Fault level limitation

33 40Taunton 132 50 Fault level limitation

33 20Alverdiscott 132 20 Fault level limitation

33 10Indian Queens 132 150 Fault level limitation

33 60Landulph 132 0 Fault level limitation

33 30Abham 132 0 Fault level limitation

33 20Exeter 132 50 Fault level limitation

33 30Axminster 132 100 Fault level limitation

33 20

Quantitative AnalysisBased on the information provided by SWEB, assuming that it may be possible to connect between 2 and 3 MW to each 11 kV network, crude analysis suggests it may be theoretically possible to connect a maximum of about 1.1 GW of suitably sized generators at appropriate locations on the SWEB network. However, the conditions required to connect this level of generation are unlikely to be met in practice and a more realistic estimate is that 430 MW of generation could be connected to the SWEB system. The details of the derivation of this estimate are included in Appendix B. It should be noted that our assessment leads to an estimated capacity to accept generation that is less than the cumulative total of the capacities suggested by SWEB in Table 4.15.3. However, the figures provided by SWEB were intended as an indication of the capacity that individual systems could accept, rather than the system as a whole, therefore the sum of these estimates would be expected to be greater than the actual total capability of the system to accept new generation.

Limiting factors for the connection of new generationThe limiting factors to the connection of new embedded generation will tend to vary with locations on the SWEB network. However, fault levels will generally limit the amount of generation that may be connected in many areas of the SWEB network, as fault levels approach the switchgear ratings. In the more remote parts of the SWEB area, such as in Cornwall, voltage regulation and thermal loading of network conductors may be of greater importance, particularly if the generation is to be located near the end of an 11 kV or 33 kV feeder.

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4.15.4 Experience of SWEB in dealing with Embedded generationSWEB acknowledged that there may be mutual benefits to both themselves and the developers of embedded generation projects. SWEB were not able to quantify any measurable benefits or drawbacks in terms of system performance and possible reduction in system losses that may have arisen due to the presence of the generator. In terms of the drawbacks associated with embedded generation SWEB were concerned that increased load forecasting errors, increased administration, increased nuisance tripping and protection difficulties could lead to more customer complaints, but that with the existing levels of embedded generation on their network this was difficult to quantify.

SWEB recognised potential benefits of having embedded generation on their system if the output of such generators could be under SWEB control. However, reluctance on the part of generators to offer such control together with the requirements of planning standards has meant that the SWEB have not been able to make full use of the potential benefits. If the levels of embedded generation continues to increase without any operational control by SWEB then the degree of operational difficulties experienced by SWEB are also likely to increase.

Page 5.1

5. TECHNICAL BENEFITS/DRAWBACKS ARISING FROM EMBEDDEDGENERATION

A distribution system is normally designed to meet the requirements of the system under maximum demand so that conductors, for example, have sufficient thermal capacity to supply the loads and that voltage regulation will remain within acceptable levels. The technical benefits that may be theoretically identified from the connection of embedded generation may on occasions only be realised in practice if suitable commercial arrangements are also implemented. In this section we attempt to identify what the potential benefits and drawbacks may arise due to embedded generation, what commercial arrangements may be used to maximise the benefits and minimise the drawbacks, and what the impact of these issues will be on the PES companies, NGC, the embedded generator and the electricity consumer.

5.1 Utilisation of distribution network assetsAs stated above, distribution systems are normally designed to meet the requirements of the system under maximum demand, plus the systems are also designed with a certain degree of redundancy to meet the requirements of the security standards. These factors generally mean that distribution assets are often operated at about 50% of their capacity. The connection of embedded generation can have two possible effects on the utilisation of distribution assets. If the generator is sized to meet the connected maximum demand and is operated at a high load factor, that is a base load station, it will tend to decrease the power flows through some of the network assets during periods of maximum demand but may increase the power flows in the same parts of the network during periods of minimum demand, thereby resulting in a change in the average level of utilisation of the asset. If there are loads connected to the circuit beyond the embedded generator then this means that the PES may be able to charge these customers use of system charges for the transferring power through an asset which, in reality, is not transmitting that power. However, if the embedded generator is rated so that it will predominately export power through the existing network assets it may reduce the peak power flows through the asset but increase the energy that the asset transmits per year, thereby increasing the utilisation of that asset. This means that the PES asset operates closer to its design rating for longer periods of the year, hence the system is worked harder. Under the present electricity trading arrangements there is no commercial recognition of this, but under the proposed revised trading arrangements it is possible that the benefit of such a change in utilisation could be identified and included in the commercial terms. If the PES were able to charge use of system charges to the generator for the increased utilisation of this asset then the revenue earned by the asset could be significantly increased. The introduction of such charges would enable the costs associated with the use of the distribution system to be more fairly allocated between load customers and generators. However, the determination of the value of the change in utilisation and the calculation of appropriate use of system charges are likely to be both complex and contentious issues that could be difficult to resolve to the satisfaction of all interested parties. The possible allocation of use of system charges is considered in Section 8 of this report.

The main distribution system assets for which the levels of utilisation will need to be considered are in transformers, overhead lines and underground cables. The life of these components is determined in part by their operating temperature, which is related to the power they carry relative to the equipment rated value. It is recognised, for example, that a transformer may be overloaded for a short period

Page 5.2

provided that it operates below its rated capacity for an equivalent period without decreasing the expected operating life. It can be seen, therefore, that by reducing the average level of utilisation in a network asset the expected operating life of that asset should be expected to be extended, although the degree to which an asset life could be extended is likely to be relatively small and difficult to quantify.

5.2 Distribution System Losses and Overall System EfficiencyThe losses on a electrical system can be considered in two different ways, either in terms of peak power loss or in terms of an annual energy loss. Peak power losses are important as these relate to the additional network capacity (generation, transmission and distribution plant) that must be included in the system design in order to meet the maximum demand2. Energy losses indicate the additional amount of energy that must be supplied by generators in order to meet the requirements of the connected demand, and in terms of generation planning is a factor in determining how much additional generation capacity should be installed on a system. However, the more important aspect of energy losses from the perspective of a PES and the regulator OFFER is the cost of supplying these losses. Losses are measured in terms of the difference between the volume of energy supplied and the value of energy purchased and as an incentive to encourage the implementation of loss reduction measures OFFER allows a PES to retain a proportion of the money arising from improvements in system efficiency. Similarly, a PES is effectively penalised for any increase in loss levels on the distribution system.

In theory, generation connected to a distribution system that is rated to match the level of local demand will tend to reduce the power losses at system maximum demand (i.e. a reduction in peak power losses), but it does not necessarily follow that the generation will also cause a reduction in the overall energy losses.

The energy losses on a distribution system maybe increased or reduced by the connection of an embedded generator, depending on the capacity, location and type of generator relative to the distribution system and the nature of the loads on the system to which it is being connected, particularly the relative generation and load profiles. If all of the generation is absorbed close to its connection point, at all times of the day and for all times of the year, it is highly likely that the generation will reduce the energy losses on the distribution system. If, however, the generation exceeds the level of local load at all times and causes large power flows back through the system into the transmission system it is likely that the generation will increase the distribution system energy losses. In many cases a generator will tend to decrease the power flows on the network during periods of peak demand but increase the power flows during periods of minimum demand and the overall effect will depend upon the balance between these extreme conditions and the change in the “average” power flows. Figure 5.1 indicates the variation in system losses that may result on a distribution system with and without the operation of an embedded generator that is rated to 40% of the network demand to which it is connected. Figure 5.1

2 It should be noted that reactive power losses (kVAr losses) are also an important consideration when assessing the available capacity in the distribution network. In many cases embedded generators import reactive power and therefore increase kVAr losses.

Page 5.3

demonstrates the importance of the generator operating regime on the overall effect on system energy losses.

Figure 5.1 General indication of the variation of distribution system losses with system demand with and without the operation of embedded generation

100%System Demand % of Maximum -Without Embedded

generation-With embedded generation

Figure 5.2 NGC load duration curve

Figure 5.2 NGC toad du'dhon cunt*

Load Duration Curve for■‘ ! m?V*f3r TrS'i', § u-j-ajjji. i_ L \ i. i t ,

Demand of Peak)

Page 5.4

The overall effect on the system energy losses will therefore be determined by the load duration curves of the distribution system to which the generator is connected and the generator operating regime. The load duration curve presented in Figure 5.2 is taken from the NGC Seven Year Statement for 1998/9 and it is to be expected that a load duration curve for most distribution systems will have a lower percentage minimum demand and a more elongated profile. The installation of a generator of a higher capacity will decrease the number of periods in the year when the generation decreases losses on the distribution system and will increase the number of periods when losses will be increased.

A generator is penalised or rewarded for its contribution to the distribution losses by the application of Loss Adjustment Factors (LAFs), or line loss factors, which enable the PES to determine, for settlement purposes, the effective generation seen at the Grid Supply Point for a combination of system demands and configurations. The calculation of LAFs enables the increase and reduction in losses for a combination of generator outputs and system loads to be evaluated, with losses being referred to the appropriate Grid Supply Point. Thus if a 1 MW generator has a loss adjustment factor of 1.02 the PES will treat an actual export of 1 MW as an effective export of 1.02 MW, thereby rewarding the generator for a 20 kW loss reduction. Conversely, if the same generator has a loss adjustment fact of 0.98 the PES will treat an actual export of 1 MW as an effective export of 0.98 MW, thereby penalising the generator for a 20 kW increase in distribution system losses. These LAFs are applied to the metered output of the embedded generator for each half hour period of the day and therefore reflect the contribution of the generator on system energy losses. However, there are only a limited number of LAFs that can be applied due to the capabilities of the settlements system. This results in approximations being made and so it is difficult to attribute an actual changes in loss levels to any particular generator. It could be considered that LAFs will tend to discourage generators from operating at times when they will be penalised for increasing system losses, but in practice the effective reduction in the generation output may not in itself make it unattractive for the generator to export power to the distribution system.

PES companies are concerned about loss levels on their system and several PESs are performing development work to enable them to more accurately calculate existing losses on their system and to evaluate the effect of changes to their system on loss levels. The development of embedded generation schemes has brought the importance of this issue to the fore within the PES companies, although the Distribution Price Control formula also requires that losses be evaluated. The determination of LAFs can be a contentious issue as the financial consequences can be significant for both the generator and the PES. The financial impact for the PES of any changes in losses should, in effect, be zero as the LAFs will pass any financial rewards or penalties on to the generator.

The effect of embedded generation on system losses is difficult to evaluate in a general sense, as indicated in Figure 5.1. Any new generation scheme must be economically viable and so its generation capacity will tend to be maximised to enable the developer to recover his investment in the shortest time possible. This can lead to the development of large generators that are sized with respect to the network capacity rather than the network demand, but such large embedded generation schemes are likely to increase losses on the local distribution system. This is consistent with the experience that many of the PES companies disclosed to M&M during this study.

Page 5.5

The effect on the overall system losses, that is the combined transmission and distribution system losses, is dependent on many factors and it is inappropriate to state in a general sense whether embedded generation will either increase or decrease the overall (transmission and distribution) system losses. An analysis performed by one utility of the overall change in system losses due to the connection of embedded generation indicated that the increase in distribution system losses on the system to which the generation was connected were not offset by the reduction in higher voltage system losses and that the overall effect was for a modest increase in system loss levels.

Studies performed by M&M on typical models of urban and rural distribution system indicate that the contribution from a generator sized to meet the maximum demand of customers within a very short distance of the generation site will tend to reduce the annual energy losses on the overall system, assuming a typical load and generation profile (i.e. the generator does not load follow). During periods of maximum demand the generator will reduce the power flows in the distribution system supplying the local load to a very low level, and during periods of lower demand the generator will export power to other loads on the same network. For such a connection arrangement the power flows will, on average, be reduced through the network. However, a generator that is rated to meet the maximum demand of the whole network to which it is connecting will tend to result in an overall increase in system annual energy losses, as the generator will result in power being exported from the system for most of the year. This causes the average conductor loading in the network to which the generator is connected to be increased, although there may be an average reduction in the loadings at higher voltage levels. Since the energy losses are related to the square of the current flows in the network, increased power flows in the lower voltage network tend to result in an increase in losses that exceed the reduction in losses in the higher voltage network.

The effect will be noticed on the transmission system as the change in power flows will produce a change in the active and reactive power losses on the NGC system, which are not passed onto an embedded generator. The costs associated with any change in losses are presently distributed across all users of the transmission system. The greatest benefit arising from any reduction in losses will be in terms of reduced energy consumption and pollution from conventional power stations, although this must be set against possible increases in pollution arising from any increase in the level of reserve that is required to secure the output from non-despatched generation.

5.3 Security and quality of supplySecurity of supply is an important issue for every participant in the electricity market. PES companies are bound by their licence to provide a supply to a defined standard and failure to comply with this standard may have severe consequences. Consumers connected to a PES system also have a keen interest in the security of supply, as do embedded generators, as the availability of a network through which the generated power can be exported, or reactive power imported, is vital to most embedded generation schemes. There are conflicting views on the contribution that embedded generation has on the security of supply. Supporters of embedded generation schemes argue that the presence of additional generation capacity on the system at location close to the demand must improve the security of supply to the local network, such that if the supply from the grid is lost the embedded generator will continue to support the demand. The contrary view is that this can only be true if the availability of

Page 5.6

embedded generation can be relied upon, that the generation itself does not require a connection to the grid (i.e. does not require a supply of reactive power) and if the system can be operated islanded from the rest of the system. In practice, however, island mode operation is unlikely to be acceptable to PES companies as the protection, operation and control implications are highly complex. The more likely benefit from embedded generation will arise in circumstances where the supply capacity form the grid is restricted by a fault or outage on the supply network, with the embedded generation providing additional capacity in order to support the connected demand.

There are arguments that suggest that embedded generation can actually decrease the security of supply in the area that it is connected. These arguments are based on the reasoning that the connection of the generation introduces more components into the distribution system and therefore there are more components that may fail. Calculations can be performed using fault statistics and generator availability data to assess and predict the performance of particular distribution systems with embedded generation schemes connected, but as for the evaluation of system losses it is likely that the affect will be highly dependant upon site specific considerations.

G59 Protection

In the event of a system short-circuit generators supply energy into the fault, which causes generators to accelerate. The final speed attained by a generator depends upon a number of factors, including the generator inertia, the impedance between the generator and the fault and the time that the generator is connected to the fault. If an embedded generator accelerates faster than other units on the system there is a risk that it could become out of phase with other units on the system, which will result in large active and reactive power flows through the system (i.e. the generator will “pole slip). In order to minimise the risk of such events occurring the Electricity Association developed a recommendation to cover the protection of embedded generating units, Engineering Recommendation G59. However, operation of the power system protection installed on the PES connection to the embedded generator may cause nuisance trips. As mentioned in Section 5.6, there is an ongoing concern with the operation of certain types of generator protection (G59 protection3) that disconnects embedded generation in the event of faults on a remote part of the system. If protection schemes operate to disconnect generation when system conditions are such that generation support is needed, then the effective demand on the distribution system will increase, voltage levels are likely to suddenly drop which may result in operation of other power system protection, resulting in sequential tripping. The loss of the embedded generator in such circumstances may make the situation worse, leading to more customers loosing supply than would have been the case if the generator had not been in service initially. PES companies are aware of the difficulties with certain types of loss of mains protection and are seeking to agree different protection schemes with developers in order to minimise the occurrence of nuisance trips.

Operation of Auto reclose schemes

3 Engineering Recommendation G59/1 “Recommendations for the connection of embedded generating plant to the Regional Electricity Companies’ Distribution Systems” includes a requirement for loss of mains protection to be provided. G59/1 relates to generators with capacities of 5 MW or less that are made at or below 20 kV, but many principles described are also applied to much larger generating units to which Engineering Recommendation G75 applies. The majority of nuisance trips are reported to be associated with the loss of mains protection.

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In order to minimise the disruption to the electricity supply to their customers PES companies have undertook a programme of installing auto-reclose schemes on their distribution networks. These schemes work on the principle that a large majority of faults on a distribution system are transitory in nature, such that a the fault may clear itself a short time after it is disconnected. Auto-reclose schemes work by reclosing the line circuit breaker a short time after being opened. If the fault is cleared the breaker will remain closed, but if the fault remains the breaker will open and the auto reclose sequence will be initiated again. It is common for an auto reclose scheme to make three attempts to clear the fault before locking out. The presence of embedded generation on a distribution system can often cause problems for such auto reclose schemes as there is a risk of the out-of phase switching if the generator continues to energise part of the PES system. This can be avoided by modifying the protection schemes, but this may increase the duration of any interruptions to the supply to customers on part of the system or may increase the number of disconnection of the embedded generator. If embedded generation trips during a reclose sequence then the distribution network must pick-up the additional load that was supplied by the generator, therefore the generator adds little to the system firm capacity and means that the PES must ensure that there is sufficient network capacity available to pick-up the demand.

Summary

The actual impact that any individual embedded generator will have on the security and quality of supply will be highly scheme dependant, and like the assessment of system losses it is inappropriate to make any general comments. However, based on the issues discussed above we consider that for non- pooled embedded generation that have not undertaken to provide a secure supply to the host PES in most cases the embedded generator will tend to cause a modest reduction to the security of supply to customers in that area.

5.4 Need for distribution reinforcementThe connection of generation may trigger reinforcement of the distribution system, typically by enhancing thermal ratings of distribution system circuits, replacing switchgear or by reconfiguring the system to accept the generation. In some cases the development of embedded generation may bring forward works that would be required at a later date to meet load related requirements, a benefit that the host PES may share with the generator. In some cases, however, the connection of a new embedded generator may necessitate reinforcement to the distribution system over and above that required for the predicted load related system development. If the developer of an embedded generation scheme is able to finance the system reinforcements then the PES company may be able to use the new assets to encourage the development of load growth in that area rather than in other areas of their system. It is possible that the development of embedded generation may enable the PES to reinforce and modernise the distribution at a reduced cost, although the bringing forward of capital expenditure may present accounting problems for the PES. As the PES capital and operational expenditure is regulated by OFFER any asset replacement work that is brought forward and was not included in the previous review period submission could force the PES to either defer other works or to seek to recover more money from the developer.

Page 5.8

5.5 Avoidance or deferment of distribution reinforcementThe connection of embedded generation may reduce the thermal loading on lines and transformers thereby extending the life of the asset (in terms of the insulation life) by extending the useful life by offsetting the demand on the asset. A PES may consider that a generator outside its direct control cannot be used under the terms of P2/5 to improve the security of the supply on a PES system. The generation can only be used to avoid/delay reinforcement if its output can be relied upon by the PES, which would lead to either strict contracts between the PES and the generator or some form of scheduling of embedded generation. An “availability agreement” is a potential option, but this is likely to require the generator to introduce some form of redundancy into his design, at cost. In general, the installation of 2 x 50 % capacity tends to add between 20 to 30% to the installed cost of a power plant and so there are strong financial pressures not to add redundancy to the design.

In Appendix D we present an example of how the economics of an availability agreement may be arranged. This analysis demonstrates that the financial benefit that an embedded generator could expect to receive from deferring reinforcement of a distribution system is, at best, similar to the additional installation cost of plant to guarantee the generator availability. This is consistent with the reluctance of developers to provide such services to PES companies. Unless the terms of “availability agreements” are made more attractive to generators it is unlikely that there will be a significant increase in their uptake.Although the output from a single embedded generating unit cannot be relied upon by the host PES, to defer reinforcement works to the distribution system, if there were a significant number of embedded generators connected to 11 kV or 33 kV networks then the reduction in demand on the 132 kV network could be recognised in the PES development plans. The overall contribution from the embedded generators would mask the variations from individual generators and effectively reduce the demand on the higher voltage system.

5.6 System control, load balance and safetyIf the development of embedded generation projects continues to such a degree where the distribution systems have a significant proportion of the systems generation connected to them, then the issue of how the system is managed and controlled will need to be addressed. At present most embedded generation with a capacity of less than 50 MW is seen by the system operator (NGC) as a reduction in demand. At the present level of embedded generation in England and Wales the changes in output from a number of embedded generation schemes does not have a significant on the overall system, as the changes in power output can not be distinguished from changes in demand. The margin of reserve set by NGC is comfortably able to accommodate such changes in generation output. However, concern has been expressed in the past about the sensitivity of generator protection to faults on the transmission system or interconnectors. Rate Of Change Of Frequency (ROCOF) relays are used to disconnect an embedded generator if there is a fault on the host PES system, in order to prevent the generator becoming islanded and ensure safe operation of the PES network. In recent years a number of nuisance trips of ROCOF relays have been recorded when there has been a fault on the transmission system, leading to concerns being expressed regarding the stability of this protection and the security of the system if a large number of generators with this type of protection all fail at the same time. The worst situation could be expected to occur if the loss of either a large

Page 5.9

generator or an interconnector caused a sudden drop in system frequency that resulted in the widespread disconnection of embedded generation schemes. There is an ongoing exercise that monitors the operation of ROCOF relays which aims to limit to risk of a mass disconnection of embedded generators. There is also research being performed to look at cost effective alternatives to this type of protection.

The connection of three phase generators to the distribution network will tend to improve the load balance on the PES network, with generators tending to act as a sink for negative phase sequence components in the supply due to either load imbalances or voltage distortions. The connection of single phase generators, either domestic CHP generators, domestic photo-voltaic cells or other DC sources will require a careful assessment to be made of the balancing of the loadings on the three phase distribution networks. It is possible that if domestic single phase generation develops to a large extent then a fundamental change in distribution network design could be required.

5.7 Implications for NGCThe implications for NGC depend to a large part on where new embedded generation is developed. If generation matches local demand so that the use of the transmission system does not continue to grow and the volume of electrical energy transported by the transmission system decreases then the revenue generated by NGC by installing new transmission plant will be restricted. However, if new embedded generation occurs in locations where generation already exceeds the demand and displaces existing generation in areas where there is a deficit, this is likely to increase the power transfers through the transmission system.

Wherever the development of new embedded generation occurs, the NGC system will still be essential in order for the PES companies to meet the requirements of their licence conditions. It is possible that although the relative quantity of real power transported may be reduced the quantity of reactive power transported could increase. This could then promote activity within the new reactive power markets with embedded generators being connected at strategic locations, such as close to the 132 kV grid supply points, to supply both real and reactive power to the PES companies. Unless there is a change in the policy for controlling the outputs of embedded generators NGC would still have the responsibility for ensuring that their is sufficient generation to meet the prospective demand but perhaps with fewer generation plants available for scheduling. This is likely to require NGC to modify the techniques used to schedule generation and to set the level of reserve.

The change in the overall structure of the electricity supply industry that will be brought about by RETA will inevitably cause the role of NGC to evolve, as it has done since privatisation. The emphasis may shift from its present role of being fundamentally a transporter of energy to that of ensuring the security and quality of supply and as such the range of services provided by NGC will also change to meet the new market conditions. The changes will also provide more customers for NGC and more challenges, both technically, organisationally and commercially.

Page 6.1

6. POTENTIAL FOR UPTAKE OF EMBEDDED GENERATION TECHNOLOGIES

In order to provide an estimate of the potential for the uptake of embedded generation technologies we have sought the views of a representative cross-section of appropriate industry stakeholders. The following categories of stakeholder have been approached

• Power plant developers• Government agencies• Contract Energy Managers• Power plant suppliers• Trade and Professional Associations• Financiers

The stakeholders were canvassed by questionnaire and personal contact to obtain their views on the projected near-term uptake of both renewable energy projects and embedded fossil fuelled projects, on a regional basis throughout England, Scotland and Wales.

A total of 65 individual stakeholders were approached but only 20% responded. Nevertheless, the responses provided a reasonable spread of views from each stakeholder category . We were able to draw some useful conclusions from the responses and these are summarised at the end of this section.

6.1 The Projected Near-term Uptake of Renewable Energy Projects in England, Scotland and Wales

6.1.1 IntroductionThis section of the report presents data and commentary that predicts the likely near-term uptake of new renewable energy projects in England, Scotland and Wales, given unconstrained access to the electricity distribution system. In this regard, ‘near-term’ is defined as the next three to five years, starting from December 1998. We have assessed the likely uptake of NFFO- and SRO-based projects, and the potential for new non-NFFO/SRO projects separately.

We have not considered here the future of NFFO-1 and NFFO-2 projects as they come out of their contracts, as these projects already exist, are connected to their local distribution systems, and will not contribute to any new additional capacity demand on the systems.

6.1.2 The uptake of NFFO and SRO projects6.1.2.1 Overall NFFO and SRO project success

It is generally accepted that not all projects that have secured contracts under the NFFO or the SRO will succeed in being built. Failure can be due to a wide range of causes such as planning difficulties, fuel availability, cost escalation or extended delays. To date, the Government have set the various ‘tranches’ of NFFO and SRO to allow for some shortfall in the uptake of contracts, so that, ultimately, a target for the actual development of projects can be reached. Each renewable energy technology or process faces peculiar ‘non-technical’ problems. It is reasonable to assume, therefore, that different success rates will apply to different technologies.

Page 6.2

As described in Appendix C, we sent a questionnaire to key stakeholders in the renewable energy sector to ask for their views on a range of issues, including a request for their opinions on the likely ongoing success rate of projects that have already secured NFFO or SRO contracts.

Detailed Questionnaire responses to this question can be found in Appendix C; we have summarised them in Table 6.1 below. This table also includes the anticipated project success rates, by technology, as published by the Scottish Office and by OFFER, in documents associated with the announcement of NFFO5 and SRO3.

Table 6.1 Estimates of Project Success Rates by TechnologyTechnology Likely Success Rate of Most Recent SRO and NFFO Projects

(% by electrical capacity)Questionnaire

ResponsesOFFER Scottish Office

Landfill Gas 50-95 95 80Energy From Waste 20-50 60 80

Large Wind 10-80 50 50Small Wind 30-70 50 50

Hydro 40-100 60 80Biomass 30-65 - -

Overall ‘average’success rate

- 65-70 -

As can be seen, questionnaire respondents’ expectations of project success varies quite widely. Due to the nature of the questionnaire response, it would not be appropriate to undertake a rigorous statistical analysis of the responses to derive ‘average’ success rates. However, it can be seen from the table above that the industry perception of renewable energy project success follows the same relative trend as the perceptions of OFFER and the Scottish Office, although industry can perhaps be said to be generally more pessimistic.

Perhaps the most substantial divergence is in the expectation of success rate for the Energy from Waste technology band, in which industry respondents expect the success rate to lie between 20 and 50%, whilst OFFER and the Scottish Office anticipate a success rate of between 60 and 80%. This may be a reflection of the severe difficulties faced by project developers in the first two tranches of NFFO, in which short NFFO contract periods, the pioneering of unfamiliar planning procedures and waste contracting, and the difficulties of the introduction of new technologies all compounded to lead to a very low success rate for this technology, particularly under NFFO2.

We have taken these views on the likely success rates for NFFO and SRO projects to derive our own ‘best guess’ of the success rates of those projects that have still to be commissioned under the most recent rounds of NFFO and SRO. In doing this, we are only interested in the development of new capacity from the end of 1998. We have therefore only considered those projects in each tranche that have yet to be developed. For example under NFFO3, almost 40% of contracted capacity is already generating so, in this case, we are only interested in what proportion of the remaining 60% will come to fruition. In deriving these technology ‘best guesses’, we have taken into account our direct knowledge

Page 6.3

and other anecdotal evidence of the position of many NFFO3, NFFO4, SRO1 and SRO2 projects that are still under development. Furthermore, we have applied different estimates of success rate for the different tranches of NFFO and SRO. The rationale behind this is that given there is now only a very limited time in which remaining NFFO3 projects can be developed before the deadline for commissioning under NFFO rules, we would anticipate that many of the still-to-be-finished projects will run out of time. However, the development process for NFFO5 has only just begun, meaning that they stand a better chance of coming to fruition.

Table 6.2 ‘Best Guess’ Success Rates for Recent NFFO and SRO Projects

Technology ‘Best guess’ success rate (% by electrical capacity)

NFFO3 NFFO4 NFFO5 SRO1 SRO2Landfill Gas (LFG) 50 80 90 80 90

Municipal and Industrial Waste (MIW) 20 40 40 - 40MIW by Combined Heat and Power - 40 40 - -

Small-scale Hydro 10 20 30 30 30Large Wind (> approx. 1 MW DNC) 20 30 30 - -

Small Wind 30 50 50 - -Wind (general) - - - 30 30

Anaerobic Digestion - 50 - - -Biomass 40 - - 100 50

Biomass by Gasification 40 30 - - -

Much argument can be had over these figures. It can be shown, however, that the conclusions to our analysis are not altered greatly by quite large changes in any one of these assumptions. We consider the above figures to be a reasonable starting point for the following analysis.

It should be noted that the industry currently faces significant uncertainty. With the Government’s review of Renewable Energy yet to emerge, many in the industry face additional hurdles in project development. One example of this is additional delays and obstructions being introduced into the planning process, pending formal announcement of Government policy with respect to Renewable Energy. Similarly, the financial community are unlikely to spend much effort in an emerging Renewable Energy scene until Government commitment is assured. The above ‘success rates’ are based on the early elimination of this uncertainty.

6.1.2.2 Uptake of NFFO3 projects

NFFO3 contracts with an aggregate capacity of 626.895 MW Declared Net Capacity (DNC) were let in 1994, covering 141 projects. Of these, as at the end of 1998, approximately 239 MW DNC were operating. A further 107 MW DNC of capacity has either been officially terminated or, in our view (based on our own knowledge of projects), are extremely unlikely to proceed. These leaves approximately 281 MW DNC still at various stages of development. This capacity can be broken down by technology as follows.

Table 6.3 NFFO3 Projects Still in Development, by Technology

Page 6.4

Technology Capacity Still in Development (MW DNC)

LFG 4.288MIW 103.246

Small-scale Hydro 3.864Large Wind 89.380Small Wind 6.691

Biomass by Gasification 19.056Biomass Residues 54.375

Total 280.900

It can also be broken down by PES Region:

Table 6.4 NFFO3 Projects Still in Development, by PES RegionPES Region Capacity Still in Development

(MW DNC)Eastern 38.528

East Midlands Electricity 34.775London Electricity 0.000

MANWEB 28.462Midlands Electricity 1.791Northern Electric 16.013

NORWEB 35.800SEEBOARD 9.000

Southern Electric 44.448SWALEC 47.765

SWEB 13.193Yorkshire Electricity 11.125

Total 280.900

Taking the assumed success rates for projects still in development, as described in Section 6.1.2.1 and presented in Table 6.2, one can derive a ‘best guess’ of what capacity is likely still to be developed under NFFO3.

All NFFO contracts are let in terms of DNC. However, the local distribution systems need to be designed and managed in terms of Maximum Continuous Rated capacity (MCR). Therefore, in order to assess the impact on the distribution system from the development of new renewable energy capacity, one must assess the likely new MCR capacity, not DNC. Within the context of NFFO and SRO, this issue only impacts on wind power projects, as for all other technologies, DNC is equal to MCR capacity. For wind, however, one must divide the expected DNC of new wind projects by 0.43 to derive the expected MCR capacity.

Having done this, one can derive data that represent our best guess of the likely new MCR capacity that each PES region’s distribution system will face from NFFO3. This is shown in Table 6.5, below.Table 6.5 ‘Best guess’ MCR Capacity to be Built from NFFO3

Page 6.5

PES Region MCR Capacity Still to be Built (MW)

Eastern 33.611East Midlands Electricity 11.390

London Electricity 0.000MANWEB 13.866

Midlands Electricity 0.826Northern Electric 7.448

NORWEB 7.825SEEBOARD 1.800

Southern Electric 10.511SWALEC 19.354

SWEB 6.657Yorkshire Electricity 4.104

Total 117.392

A similar approach can be adopted in the assessment of other NFFO and SRO tranches.

6.1.2.3 Uptake of NFFO4 projects

NFFO4 contracts with an aggregate capacity of 842.719 MW DNC were let in 1997, covering 195 projects. Of these, as at the end of 1998, approximately 40 MW DNC were operating. As yet, no projects have officially terminated, and it is too soon to state with any confidence that any are extremely unlikely to proceed. Therefore, we judge that there are approximately 802 MW DNC still at various stages of development. This capacity can be broken down by technology as follows.

Table 6.6 NFFO4 Projects Still in Development, by TechnologyTechnology Capacity Still in Development

(MW DNC)LFG 134.012

MIW by Combined Heat and Power 115.288MIW by Fluidised-bed Combustion 125.927

Small-scale Hydro 12.526Large Wind 330.359Small Wind 10.326

Anaerobic Digestion 6.580Biomass 67.335

Total 802.353

It can also be broken down by PES Region as shown in Table 6.7 below.

Page 6.6

Table 6.7 NFFO4 Projects Still in Development, by PES RegionPES Region Capacity Still in Development

(MW DNC)Eastern 88.971

East Midlands Electricity 17.243London Electricity 22.000

MANWEB 121.449Midlands Electricity 6.260Northern Electric 73.242

NORWEB 246.614SEEBOARD 46.737

Southern Electric 31.200SWALEC 44.622

SWEB 34.322Yorkshire Electricity 69.693

Total 802.353

Again, taking the assumed success rates for projects still in development, as described in Section 6.1.2.1 and presented in Table 6.2, one can derive a ‘best guess’ of what capacity is likely still to be developed under NFFO4. Furthermore, converting DNC to MCR capacity, one can derive the following data:

Table 6.8 ‘Best guess’ MCR Capacity to be Built from NFFO4PES Region MCR Capacity Still to be Built

(MW)Eastern 62.516

East Midlands Electricity 10.230London Electricity 8.800

MANWEB 84.084Midlands Electricity 4.876Northern Electric 41.501

NORWEB 134.777SEEBOARD 21.611

Southern Electric 15.660SWALEC 25.661

SWEB 17.355Yorkshire Electricity 45.111

Total 472.181

6.1.2.4 Uptake of NFFO5 projects

NFFO5 contracts with an aggregate capacity of 1177.145 MW DNC were let in 1998. To date, none is completed and none has terminated, so all can be said to still be in development. This capacity can be broken down by technology as follows.

Page 6.7

Table 6.9 NFFO5 Projects Still in Development, by TechnologyTechnology Capacity Still in Development

(MW DNC)LFG 313.728MIW 415.748

MIW by Combined Heat and Power 69.971Small-scale Hydro 8.865

Large Wind 340.161Small Wind 28.672

Total 1177.145

It can also be broken down by PES Region:

Table 6.10 NFFO5 Projects Still in Development, by PES RegionPES Region Capacity Still in Development

(MW DNC)Eastern 281.797

East Midlands Electricity 81.542London Electricity 35.100

MANWEB 49.272Midlands Electricity 54.263Northern Electric 171.200

NORWEB 127.632*SEEBOARD 68.809

Southern Electric 49.395SWALEC 69.377

SWEB 54.220Yorkshire Electricity 122.001

NFPA** 12.537Total 1177.145

* It should be noted that there are two large windfarms contracted under NFFO5, with an aggregate DNC of 50.379 MW, which

are nominally in the NORWEB PES region but which are actually planned to be located close to Langholm in Dumfries and

Galloway. At this stage, it is unclear exactly how such capacity, if built, will connect into the electricity transmission/distribution

system. It is believed that if the projects proceed, they will be connected directly to the Scotland-England 132 kV

interconnection. Under such circumstances, and solely for the purposes of this study, we should associate this capacity with

Scottish Power’s system (rather than NORWEB’s), as they own and operate this interconnection. This has been taken into

account in the following analyses and tables.

** Actual capacity is in the Scottish Hydro-electric PES region.

Again, taking the assumed success rates for projects still in development, as described in Section 6.1.2.1 and presented in Table 6.2, one can derive a ‘best guess’ of what capacity is likely still to be developed under NFFO5. Furthermore, converting DNC to MCR capacity, one can derive the data in Table 6.11.

Page 6.8

Table 6.11 ‘Best guess’ MCR Capacity to be Built from NFFO5PES Region MCR Capacity Still to be Built

(MW)Eastern 157.776

East Midlands Electricity 60.151London Electricity 14.040

MANWEB 34.766Midlands Electricity 37.624Northern Electric 105.227

NORWEB 61.987*SEEBOARD 41.605

Southern Electric 34.897SWALEC 45.216

SWEB 29.090Yorkshire Electricity 83.689

Scottish Power 35.148*NFPA** 8.747Total 749.963

* See note to Table 6.10, above.

‘‘Actual capacity is in the Scottish Hydro-electric PES region.

6.1.2.5 Uptake of SRO1 projects

SRO1 contracts with an aggregate capacity of 76.440 MW DNC were let, covering 30 projects. Of these, as at the end of 1998, approximately 28 MW DNC were operating, with only one very small project terminated. This leaves approximately 49 MW DNC still at various stages of development. This capacity can be broken down by technology as follows. It can be noted that SRO actually grouped together landfill gas (LFG) and municipal and industrial waste (MIW) schemes into a single technology band. We have split them here, however, to differentiate the technologies because we would expect them to be subject to different success rates, as discussed in Section 6.1.2.1.

Table 6.12 SRO1 Projects Still in Development, by Technology

Technology Capacity Still in Development (MW DNC)

LFG 0.000Small-scale Hydro 14.910

Wind 23.840Biomass 9.800

Total 48.550

It can also be broken down by PES Region:

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Table 6.13 SRO1 Projects Still in Development, by PES RegionPES Region Capacity Still in Development

(MW DNC)Scottish Power 13.170

Scottish Hydro-electric 35.380Total 48.550

Again, taking the assumed success rates for projects still in development, as described in Section 6.1.2.1 and presented in Table 6.2 (this time adjusted to take account of known progress at some projects), one can derive a ‘best guess’ of what capacity is likely still to be developed under SRO1. Furthermore, converting DNC to MCR capacity, one can derive the data in Table 6.14.

Table 6.14 ‘Best guess’ MCR Capacity to be Built from SRO1PES Region MCR Capacity Still to be Built

(MW)Scottish Power 12.151

Scottish Hydro-electric 18.754Total 30.906

6.1.2.6 Uptake of SRO2 projects

SRO2 contracts with an aggregate capacity of 114.040 MW DNC were let, covering 26 projects. As at the end of 1998, none has been commissioned, and none has been terminated. All of the projects can therefore be considered to be in development. This capacity can be broken down by technology as follows. As with SRO1, SRO2 actually grouped LFG and MIW into a single technology band. We have, however, split them here to differentiate the two technologies as they are likely to see different project success rates.

Table 6.15 SRO2 Projects Still in Development, by TechnologyTechnology Capacity Still in Development

(MW DNC)LFG 9.350MIW 46.700

Small-scale Hydro 12.360Wind 43.630

Biomass 2.000Total 114.040

It can also be broken down by PES Region:

Table 6.16 SRO2 Projects Still in Development, by PES RegionPES Region Capacity Still in Development

(MW DNC)Scottish Power 62.090

Scottish Hydro-electric 51.950Total 114.040

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Again, taking the assumed success rates for projects still in development, as described in Section 6.1.2.1 and presented in Table 6.2 (once more, adjusted to take account of known progress at some projects), one can derive a ‘best guess’ of what capacity is likely still to be developed under SRO1. Furthermore, converting DNC to MCR capacity, one can derive the data in Table 6.17.

Table 6.17 ‘Best guess’ MCR Capacity to be Built from SRO2PES Region MCR Capacity Still to be Built

(MW)Scottish Power 29.874

Scottish Hydro-electric 33.838Total 63.713

6.1.2.7 Uptake of SRO3 projects

As at the time of preparing this report, the outcome of the SRO3 bidding process is unknown.

However, we would expect that an order will be set that will lead to the development of approximately 120 MW DNC, or approximately 200 MW MCR capacity. Based on experience under SRO2, it may be reasonable to expect this capacity to be split equally between the regions of Scottish Power and Scottish Hydro-electric. It must be emphasised that these expectations should be considered very much as ‘guestimates’, but given trends in development of NFFO and SRO to date, and the stated objectives of the Government, we would consider them to be reasonable.

In addition, as noted in Section 6.1.2.4, there are two large windfarms contracted under NFFO5 located near Langholm that, if built, will be connected (at least for the purposes of this analysis) to the Scottish Power system. An expectation of some capacity from these projects is included in our analysis.

6.1.2.8 NFFO/SRO conclusions

Based on the analyses presented in Sections 6.1.2.2 through to 6.1.2.7, we can derive our expectation for the near-term uptake of renewable energy projects supported by NFFO and SRO. As stated in Section 6.1.2.1, we have not considered existing NFFO1 and NFFO2 projects that are entering a new commercial phase of their lives, as they do not represent a new technical demand on the distribution systems of their host PESs. Furthermore, we have not considered the impact of future tranches of NFFO or SRO (save for SRO3). This is because any projects supported under these schemes are unlikely to be fully developed and connected to the distribution systems within the next three to five years - the timescale of interest for this study.

Using the preceding analyses, therefore, we can derive the following Table 6.18. For information, we have also included the expected uptake of renewable energy projects in terms of DNC.

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Table 6.18 Likely Near-term Uptake of New Renewable Energy Projects Supported by NFFO/SROPES Region MW MCR Capacity (MW) Total

NFF NFFO NFFO SRO SRO SRO Total DNCO3

4 5 1 2 3

Eastern 33.6 62.5 157.8 - - - 253.9 220.3EME 11.4 10.2 60.2 - - - 81.8 81.5LE 0.0 8.8 14.0 - - - 22.8 22.8MANWEB 13.9 84.1 34.8 - - - 132.7 72.5Midlands Electricity 0.8 4.9 37.6 - - - 43.3 42.5Northern Electric 7.4 41.5 105.2 - - - 154.2 97.1NORWEB 7.8 134.8 62.0 - - - 204.6 136.3SEEBOARD 1.8 21.6 41.6 - - - 65.0 65.0Southern Electric 10.5 15.7 34.9 - - - 61.1 60.0SWALEC 19.4 25.7 45.2 - - - 90.2 57.4SWEB 6.7 17.4 29.1 - - - 53.1 41.3Yorkshire Electric 4.1 45.1 83.7 - - - 132.9 105.0Scottish Power - - 35.1 12.2 29.9 100.0 177.2 115.9Scottish HE - - 8.7 18.8 33.8 100.0 161.3 95.8TOTAL 117.

4472.2 750.0 30.9 63.7 200.0 1634.2 1213.5

We conclude, therefore, that approximately 1.6 GW of maximum continuous rated electrical capacity is likely to be built in England, Scotland and Wales, supported by NFFO and SRO, in the next three to five years (over 1.2 GW of DNC). The PES regions that will face the greatest demand on their system for connections will be those of Eastern and NORWEB, both of whom are likely to face over 200 MW (MCR) of new installed renewable energy capacity, with those of Scottish Power, Scottish Hydro-electric, Yorkshire Electricity and MANWEB each needing to accommodate around 150 MW.

6.1.3 The Uptake of Renewables Outside of NFFO and SROThis topic is much less suited to the analytical methodology we have used above in the expectation of NFFO and SRO supported capacity.

The prospects for large-scale near-term uptake of renewable energy capacity outside of these support mechanisms is generally considered to be small. It is true that there is strong downward pressure on the contract price available under NFFO and SRO, so much so that, certainly for some technologies, the claim of ‘price convergence’ seems to be well founded. However, NFFO and SRO not only offer a premium (however small that may be), they offer a guaranteed long-term offtake market for the generated electricity. This is an extremely valuable element in any project, taking away what would otherwise be a significant financing risk. Elimination of risk brings down the cost of finance and makes it more readily available, making the projects more commercially viable. This aspect of the support offered by NFFO and SRO may be considered by many to be the most influential part of these mechanisms, particularly at a time in the Electricity Supply Industry when all of the trading arrangements are undergoing review and revision.

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As part of our study questionnaire, we asked key renewable energy industry stakeholders whether they thought there might be any uptake of new renewable energy capacity in the next three to five years, outside of the NFFO/SRO support mechanisms. Again detailed responses are presented in Appendix C, but respondents’ views, by technology, are summarised below.

Table 6.19 Estimates of New Renewable Energy Uptake Outside of NFFO/SRO in the Near Term

Technology Questionnaire Responses on the Development of non-NFFO/SRO Projects

(MW DNC)LFG 0-10MIW 0-50

Small-scale Hydro 0-10Large Wind 0-200Small Wind 0-5

Biomass 0-10Total 0-285

As can be seen, there is a substantial range in what industry players consider may be possible outside of the NFFO/SRO mechanisms, particularly with regard to Wind. Given the timescales that we are considering in this study, the authors would take the view that the prospects for uptake of renewable energy outside of NFFO/SRO lie around the middle of the range presented above, and that this capacity will be dominated by Wind and some LFG. We would consider the prospects for the development of numerous MIW plants outside of NFFO/SRO to be small in the next five years (not least because of the lead time for such projects).

Our best guess for the total prospective new non-NFFO/SRO capacity is 200 MW MCR capacity (100 MW DNC), with the distribution by PES as shown in Table 6.20.

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Table 6.20 ‘Best guess’ of New Renewable Energy Uptake Outside of NFFO/SRO in the NearTerm

PES Region Non-NFFO/SRO MCRCapacity (MW)

Non-NFFO/SRO DNC(MW)

Eastern 10 5East Midlands Electricity 0 0

London Electricity 0 0MANWEB 20 10

Midlands Electricity 0 0Northern Electric 20 10

NORWEB 20 10SEEBOARD 10 5

Southern Electric 0 0SWALEC 20 10

SWEB 10 5Yorkshire Electricity 10 5

Scottish Power 40 20Scottish Hydro-electric 40 20

Total 200 100

6.1.4 ConclusionsThe uptake of renewable energy projects in England Scotland and Wales in the next five years will be dominated by the development of contracted NFFO and SRO projects. Not all of those currently in development will succeed, and the success rate will be influenced by factors such as fuel supply, planning obstacles, and financing. We would, however, expect there to be some limited uptake of renewable energy projects outside of the NFFO/SRO mechanism, dominated by wind energy, some landfill gas, and with perhaps a very few municipal and/or industrial waste projects.

In aggregate, we would expect the PES distribution systems to face the following demands for the installation of new capacity in the timescale of this study. For information, Table 6.21 also includes our expectation of total DNC that will be built by PES area in the near-term.

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Table 6.21 Expectation of New Renewable Energy Capacity in the Next 3-5 YearsPES Region Near-term New RE Capacity (MW MCR) Total MW

DNCNFFO/SRO Non-NFFO/SRO

Total

Eastern 254 10 264 225East Midlands Electricity 82 0 82 82

London Electricity 23 0 23 23MANWEB 133 20 153 83

Midlands Electricity 43 0 43 42Northern Electric 154 20 174 107

NORWEB 205 20 225 146SEEBOARD 65 10 75 70

Southern Electric 61 0 61 60SWALEC 90 20 110 67

SWEB 53 10 63 46Yorkshire Electricity 133 10 143 110

Scottish Power 177 40 217 136Scottish Hydro-electric* 162 40 202 116

Total 1634 200 1834 1314*Includes NFFO capacity to be built in the Scottish Hydro-electric PES region but as contract awarded under NFFO rather than

SRO the host PES is not obliged to take the output, hence the NFPA purchase the generation directly.

We conclude, therefore, that approximately 1.8 GW of maximum continuous rated electrical capacity is likely to be built in England, Scotland and Wales within the next five years (approx. 1.3 GW DNC). The PES regions that will face the greatest demand on their system for connections will be those of Eastern, NORWEB, Scottish Power and Scottish Hydro-electric, all of whom may face more than about 200 MW of new installed renewable energy capacity, with those of MANWEB, Northern Electric and, perhaps, Yorkshire Electricity having to accommodate more than about 150 MW each.

6.2 The Projected Near-term Uptake of Embedded Fossil-fuelled Projects in England Scotland and Wales

6.2.1 IntroductionThis section of the report presents our ‘best guess’ estimation of the likely new build of fossil-based CHP and other embedded generation plant in England, Scotland and Wales in the next three to five years.

We also include an overview of factors influencing project success as these items affect the predictions. The discussion and analysis we present here is based on the responses given by key industry stakeholders combined with our interpretation and analysis of these responses. The latter takes account of our own understanding of the market and rate of project development to date.

Details of the full Questionnaire and the responses can be found in Appendix C of this report. In the following sections we present a commentary on the Developers View of embedded generation, based on responses to our Questionnaire, together with a discussion of the major barriers to the uptake of

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such projects and what can be done to maximise the potential. The conclusions of our assessment for the uptake of embedded fossil fuelled generation are presented in Section 6.2.5.

6.2.2 Near-term Uptake of Embedded Generation in England, Scotland and WalesRespondents’ expectations of the likely near-term uptake of CHP plant ranged from installed capacities of 0 to 2000 MWe. Expectation of non-CHP embedded plant uptake ranged from installed capacities of 100 MWe to 600 MWe.

The climate for granting consent, especially to larger gas-fired projects, has worsened with the stated Government moratorium on new gas-fired power plant. It can be noted that some projects with installed capacities of less than 100 MWe capacity have recently been granted Section 36 and Section 14 consents under the Electricity Act of 1989 and the Energy Act of 1976. These consented projects have an aggregate capacity of close to 200 MWe. Further projects are known to be under consideration, but it remains to be seen whether the recent approvals for CHP with power export indicate a trend such that developers can make applications with more confidence.

All of the responses to the Questionnaire indicate a level of anticipated uptake that will be well short of stated Government targets to at least double the current 4,000 MWe in the coming decade. (DETR News Release 19/11/98). We note that one respondent suggests that more than 8 GWe of installed CHP capacity will be needed in the timescale covered by this study in order to meet CO2 reduction targets and this should be reconciled in the stated targets. We further believe that inducements of some kind are vital to avoid a significant shortfall. Such support is considered to be urgently needed and if not forthcoming in the near term the eventual inducements will require to be of greater value to close the gap.

We understand that delays in the consents process post-moratorium affected projects with a total capacity of approximately 500 MW. The consents process may now be easing and there could be a backlog of projects that were not submitted in anticipation of refusal that now feel sufficiently confident to proceed with a consent application. There may, therefore be a short term rush to develop known prospects that will then ease. In the medium term, market forces may reduce the viability of new CHP projects, or government initiatives may actively stimulate growth in the sector.

Assuming the “best case” of government action to prevent negative issues impacting CHP with perhaps limited positive inducement, we would regard the circa 100 MW schemes as exceptional with the “best” sites having been supplied already so expect the development of less than 1 such scheme per year.For schemes with installed capacities in the range 40 to 55 MW, based on the range of price competitive, efficient machines we expect the development of perhaps 3 to 5 schemes per year. The schemes based on albeit excellent 15 to 25 MW machines has become harder to justify economically and we expect that there may be no more than 6 to 10 such schemes developed per year.

In our view, taking account of historical data and noting the above “best case” scenario, our estimate for the near-term (5 year) uptake of such embedded plant, whether CHP or not, is for installed capacities between 320 and 550 MWe per year.

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Assuming no Government action to prevent negative issues impacting CHP and no positive inducement, we would regard the stated Government target as unrealistic and would expect less than 300 MW of new CHP installed capacity to be developed per year.

For the purposes of assessing impact on the distribution system, our estimate for the next 5 years is 1,500 to 2,750 MWe installed capacity.

6.2.3 Likely Location of Successful ProjectsIt is clear that any CHP or other ‘industrial’-scale power project will be sited wherever there is a suitable opportunity: heat load, demand with appropriate load factor, fuel pricing, prospects for electricity offtake, etc., all will influence the location of such project. One cannot easily predict where such projects are likely to be. Nevertheless, our Questionnaire asked for views on where respondents thought projects might be built; their thoughts are summarised below.

Table 6.22 Expected Location of new Fossil-fuelled Embedded Plant, by PES RegionPES Region Likely uptake of CHP Likely uptake on non-CHP

Capacity (MWe) embedded capacity (MWe)Eastern 10-150 3-40East Midlands Electricity 10-100 5-40London Electricity 10-100 5-100MANWEB 35-400 2-30Midlands Electricity 25-300 5-40Northern Electric 25-100 2-30NORWEB 10-300 2-40SEEBOARD 25-100 25-50Southern Electric 10-100 25-100SWALEC 10-400 10-20SWEB 20-50 10-40Yorkshire Electricity 35-200 2-40Scottish Power 35-200 2-40Scottish Hydro-electric 5-50 2-10

As can be seen, respondent’s expectations of the uptake in each PES region varies quite widely (reflecting the widely varying expectations for the country as a whole, presented in Section 6.2.2), but the data does indicate that there are some PES regions where one might expect greater uptake of such projects. Not surprisingly, the data suggest the traditional industrial areas could attract the largest installed capacity.

Whilst the issues associated with connection to the distribution system will impact project developers, we believe that the existence or otherwise of a good heat load is key to CHP project viability, and business requirements are necessary to justify non-CHP embedded generation. The best schemes will therefore be based on businesses which require the facility to increase competitiveness.

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As would be expected, the predicted figures show fossil-fuelled non-CHP as having less potential than CHP. This supports the premise, based on hard economics, that without revenue from heat sales (or avoided fuel cost for heating), it is less easy to justify the business case for such projects.

6.2.4 Factors Influencing Project SuccessRespondents were asked to give their views on the overall success rate of prospective CHP and other embedded projects. Overall, the estimated ‘success rate’ varied from 10 to 60% for CHP projects, and from 0% to 70% for non-CHP fossil fuelled embedded power projects. It is significant that only one respondent indicated greater than a 50% success rate for viable CHP projects. Again, only one other respondent indicated greater than 50% for non-CHP projects. In response to this question, one respondent suggested that given the current moratorium on new gas-fired power plant, a 50% success rate for non-CHP projects would be very optimistic.

Some patterns emerged from various questions aimed at elucidating on what are the key factors influencing project success.

Consensus came across from Questionnaire responses, in that delay, uncertainty, and apparently inconsistent approaches from host PESs led to frustration and some risk to projects. This is perhaps, a second order effect relative to economic factors.

Certainly size of project was seen by most respondents to be important. We agree with this and believe that the cost per kW of installed plant increases steeply as size falls below the section 36 threshold of 50 MW until the point where small, packaged sets become competitive, usually based on reciprocating spark-ignition gas engines as prime movers (at around 4 to 5 MW). This point opens up a debate regarding the development of true power/heat match projects versus relatively large projects for a specific application, with excess power being exported. That is, would a relaxation on size to allow export of a higher electricity surplus open up the way for more, successful projects?

If power export from projects were to be acceptable to Government, given an overall plant efficiency above a stated threshold (say, 70%), then developers would be able to proceed with a higher degree of certainty than hitherto. As stated previously, recent government approvals for CHP with power export indicate that there may be movement in this area. There is still sufficient uncertainty as to pose a problem to prospective project developers but confidence may grow as more projects gain Section 14 and/or 36 consent.

Another key issue referred to by many of the respondents is low energy prices, making the economic case for such relatively small projects very difficult to make.

None of the respondents could envisage any significant changes to these issues in the next three to five years.

District Heating is an important part of government targets for CHP. With specific reference to the prospect for and barriers to the uptake of DH projects, key issues to emerge from responses included the higher risk associated with such projects, the infrastructure costs, pressure on land for sites, and heat customer reluctance to commit prior to commissioning. In our view, this area may be the biggest gap between Government plans for CHP and industry practicalities. Small schemes will continue to be

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installed for individual hotels, hospitals, offices or other suitable loads. As time passes, the best opportunities will be taken up and the rate of installation may slow down. Even without a slow down, a large number of small schemes is needed to meet the targets and we see little indication that this will in fact happen. Without major change, designed to encourage larger schemes, government targets will not be met.

6.2.5 Conclusions

Predicting the near-term uptake of fossil-fuelled embedded generation plant (both CHP and non-CHP) in England, Scotland and Wales is extremely difficult, particularly at this time of substantial uncertainty and change in the Electricity Supply Industry.

Nevertheless, based on responses to our Questionnaire, known project developments recently awarded relevant Consents under the Electricity Act of 1989 and the Energy Act of 1976, and our own understanding of the state of the industry, we would suggest that an installed capacity of between 1,500 and 2,750 MWe of fossil-fuelled embedded generation plant could be developed in the next five years.

Should there be strong government policy in the form of inducements or other short term change, developers may find more projects become viable. It could be that such change would produce on- target results but this is difficult to predict. It should also be noted that there would be an 18 months to 2 year lead time to develop, engineer and construct such plants which rules out short term, significant increases. This requires even greater rate of take up in year 2001 and beyond to meet 2010 objectives.

Whatever the rate of development, we expect that most of this capacity will be in the form of gas fired CHP plant with power export. We do not anticipate growth in District Heating in cities, based on CHP and power export. Furthermore, most of these CHP projects will be developed in the traditional industrial areas England, Scotland and Wales. It is in these regions that the impact on the local distribution systems will be highest.

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7. COMPARISON OF DISTRIBUTION NETWORK CAPACITY WITH POTENTIALUPTAKE

In this section we compare the indicative capability of PES networks to accept the new generation described in Section 4 with the potential uptake of embedded generation technology derived in Section 6 of this report. Table 7.1 summarises the indicative capacities that M&M expect that each PES could be expected to accept with M&M’s forecast uptake of renewable energy and fossil fuelled embedded generation projects.

Table 7.1 Comparison of network capability to accept new generation with potential uptake

Likely uptake ofPES Region Indicative renewable CHP non-CHP Total generation

network energy Capacity capacity capacitycapacity MW (MWe) (MWe) MWe

Eastern 910 264 10-150 3-40 277-454East Midlands Electricity 920 82 10-100 5-40 97-222London Electricity 390 23 10-100 5-100 38-223MANWEB 460 153 35-400 2-30 190-583Midlands Electricity 330 43 25-300 5-40 73-383Northern Electric 250 174 25-100 2-30 201-304NORWEB 620 275 10-300 2-40 287-615SEEBOARD 710 75 25-100 25-50 125-225Southern Electric 1270 61 10-100 25-100 96-261SWALEC 210 110 10-400 10-20 130-530SWEB 430 63 20-50 10-40 93-153Yorkshire Electricity 650 143 35-200 2-40 180-383Scottish Powerf 810* 217 35-200 2-40 254-457Scottish Hydro-electricf 110* 193 5-50 2-10 200-253

f These indicative capacities assume that there will be no transmission constraints imposed by the capacity of the Scotland-

England interconnector. In practice it is possible that access to the interconnector may limit the capacity of new generation that

can be connected in Scotland

* Assuming SRO contracted generation is not connected

Table 7.1 indicates that there should, in theory, be sufficient network capacity to accept the forecast levels of embedded generation in the next 5 years, although in the Manweb and SWALEC PES regions there could be difficulty accommodating the higher forecast uptake. However, these indicative capacities have assumed that generation will be distributed throughout the PES territory and it is likely that a large proportion of the generation capacity will be concentrated in a relatively small number of areas. Table 7.1 should not, therefore, be interpreted as an expectation of the total amount of generation that will be connected, but it does indicate in general terms where the most difficulties may be experienced in developing the forecast levels of embedded generation.

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The areas in which the distribution systems may experience the most difficulties in meeting the forecast development of embedded generation are Northern, Manweb, Midland Electricity, SWALEC and Scottish Hydro-Electric. In the case of SWALEC and Scottish Hydro-Electric there a number of renewable energy schemes that have been awarded contracts but have yet to proceed that could, if developed, take a significant proportion of the available network capacity in a number of areas.

There are a large number of PES systems that are operating close to their fault level limit and it is possible that the potential developments indicated by our survey of industry stakeholders will occur in areas such as these. CHP developments will generally tend to occur in industrial areas, and it is often the case that fault levels are in industrial areas are higher than those found in other areas due to the nature of the connected loads. There may, therefore, be some difficulty in connecting CHP loads in PES areas such as Manweb, SWALEC, Midlands Electricity, London Electricity and Yorkshire Electricity where fault levels in industrial areas are particularly close to switchgear ratings.

In order to maximise the connection of embedded generation projects it is desirable to have a large number of small generation schemes that are connected close to load centres. Such an approach should minimise system losses, minimise the increase in system fault levels but it is expected that this will not be viable commercially as project developers seek to maximise their revenue by maximising the generation output form each site.

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8. POSSIBLE SOLUTIONS TO OVERCOME OBSTACLES

The present technical, commercial and regulatory arrangements with which embedded generation schemes must comply do not always enable the maximum benefit to be obtained from the presence of embedded generation on distribution systems. There are numerous good reasons why the present arrangements have evolved, but in this section we aim to identify methods of overcoming potential obstacles to the connection of embedded generation. The obstacles may be technical, commercial, regulatory or a combination of these, and the solution to obstacles may be found through careful consideration of how the generation is connected and operated. It is to be expected that if the Governments stated targets for levels of renewable energy sources and CHP schemes are to be realised then some significant changes to the procedures used to connect and operate embedded generation may be required. In this section we aim to outline a number of possible solutions in order to encourage further debate.

There are basically three fundamental technical obstacles to the connection of new embedded generation, voltage regulation, thermal loading and fault levels, although in some cases other aspects may be as important. These other issues may include power system protection co-ordination, levels of harmonic distortion, system earthing and security of supply considerations.

The present regulatory arrangements that are in place were largely developed when the PES companies were primarily expected to deal with demand customers with a much smaller number of generation customers. The PES licence therefore has a large number of conditions that relate to the connection of new loads, but less emphasis is given to the connection of embedded generators, especially the consequences of large scale penetration of embedded generation. A change in emphasis in the rules governing connections to and use of the distribution systems so that there is greater similarity between the terms relating to load and generation customers should enable both the PES companies, load customers and, in the long run, embedded generators to use and develop the distribution systems in an equitable and cost effective manner.

8.1 Voltage regulationCause of problemIn Section 3 we outlined the statutory requirements that determine how a PES must design and operate its distribution system. In Section 4 we identified the planning guidelines that the PES companies have adopted to ensure that their system complies with these statutory requirements and the more specific requirements that are appropriate for their systems. The connection of an embedded generator will change power flows (and reactive power flows) on the distribution system, which may lead to voltages that are outside the permitted range unless suitable corrective measures are taken. A sudden change in generator output may result in a change in system voltage that is outside the permitted range and so the PES and the generator must design a connection that will prevent such excessive voltage changes occurring. The PES companies must ensure that the generation can be accepted for all combinations of generation output and system load and in many cases the largest voltage changes occur when there is maximum generation and minimum demand on the distribution system. In such cases the reinforcement works required are determined by a combination of system conditions that may exist for only a relatively short period of each year.

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Possible Technical solutions1. In order to reduce the magnitude of voltage changes and to reduce the voltage level at the

connection point of the embedded generator it is often necessary to reduce the impedance of the connection to the source substation. This can be achieved by installing new conductors in the circuits back to the source substation, which usually has an associated benefit of increasing the thermal capacity of that section of line.

2. A direct connection may be made back to the source substation, thereby reducing the effect on the supply to other customers from changes in generator output

3. Restriction on the operating power factor of the embedded generator. Many embedded generators that are connected to 11 kV and 33 kV networks use induction generators and it is relatively straightforward for the operating power factor of these machines to be fixed within a predetermined range.

4. Installation of reactive compensation to control the voltage at the connection point may be considered. This may take the form of a relatively crude control scheme that switches banks of capacitors according to the connection point voltage, or it may be a more sophisticated Static VAr Compensator (SVC). SVCs employ power electronic devices to control the amount of reactive compensation that is required to maintain system voltages within predetermined limits.

5. The generator power output may be controlled according to the level of demand on the distribution system, in a load following arrangement. Not all types of generation will be suitable for operation in this way due to the variability of their energy source. The implementation of a load following scheme will require a signal to be provided from the PES source substation. It is possible that if more than one embedded generator were to connect to the same system then some operational difficulties would be encountered.

6. Connect the generator to a higher voltage system.

Possible Commercial solutions1. If the duration of the period when operation of the generation is shown to cause or potentially cause

voltage regulation outside the permitted range is limited, then the generator could consider not operating at these times. Such a commercial arrangement would need to be supported by appropriate technical measures, but it is likely that significant savings could be made in the cost of system reinforcements.

2. The generator could be prepared to indemnify the PES against any claims made against it as a result of voltages, or voltage changes that are outside acceptable ranges. This is not thought to be an attractive option for either the PES or the generator.

Possible Regulatory solutions1. As mentioned above, the design of generator connections that ensure that the maximum generation

capacity can be accepted for all system demands can result in extensive reinforcement of the distribution system being required. This is particularly true for renewable generators applying

Page 8.3

for connections under NFFO and SRO as the PES is obliged to accept the generators’ output whenever it is available. By replacing the “must take” obligation of NFFO and SRO contracts with a more flexible agreement that allows the generation to be constrained off at certain times it is likely that the cost of developing these schemes will be reduced. This should help to promote the development of more renewable generation projects.

2. By permitting PES companies to have more control over the operation of embedded generators connected to their system, with the introduction of some form of despatching based on technical grounds (as opposed to economic scheduling), the PES can exercise dynamic control of their system. This should enable more generation to be connected to the system, although the cost of providing the system control will need to be determined. It is possible that the cost of providing such a service could be included in future distribution price control reviews.

8.2 Thermal LoadingCause of the problemEach part of the distribution system has a design rating within which it can operate safely. It maybe possible to exceed this limit for a short time under emergency conditions, but generally the PES will design and operate its system so that equipment operates within the design rating. The connection of an embedded generator will change the power flows on the distribution system which may result in parts of the system becoming overloaded. In some cases it is the flow of reactive power that causes the overloading. In many cases the largest voltage changes occur when there is maximum generation and minimum demand on the distribution system, hence it is a combination of system conditions that exist for only a relatively short period of the year that define the necessary reinforcement works.

Possible Technical solutions1. Increase the thermal capacity of the existing circuits back to the source substation. This may require

sections of line to be replaced with new conductors, which will normally have an associated benefit of reducing voltage regulation on the circuit.

2. Some lines can have their capacity increased by as much as 10% by re-profiling the lines.

3. Restricting the range of generator power factors can help reduce reactive power flows on the distribution network to prevent conductor overloading.

4. By controlling the generator output so that it follows the system demand overloading should be avoided.

5. Connect to a higher voltage system.

Possible Commercial solutions1. If the duration of the period when operation of the generation is shown to cause, or potentially cause,

overloading of distribution system circuits the generator could consider not operating at these times. Such a commercial arrangement would need to be supported by appropriate technical measures, but it is likely that significant savings could be made in the cost of system reinforcements.

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Possible Regulatory solutions1. As mentioned above, by allowing the PES to constrain generation connected to their system it should

be possible to avoid some network reinforcement. This will require the terms of NFFO and SRO contracts to be reviewed if the output of these generators can be controlled in this way

8.3 Fault levelsCause of problemThe PES has an obligation to ensure that the distribution system is operated in a safe and co-ordinated manner. If there is a fault on the system it is necessary to disconnect and isolate the faulty part of the system, and to ensure that this can be achieved it is necessary for switchgear to be able to break the maximum prospective fault current. If a circuit breaker closes onto a short circuit the circuit breaker contacts will pass the peak fault current, which is known as the “make” duty. In order that the switchgear can operate safely it is essential that fault levels on the distribution system do not exceed the equipment rating. In order to demonstrate this the PES will perform studies in accordance with agreed procedures that enable the maximum prospective fault level to be calculated. Many PES companies allow a margin between the calculated prospective fault level and the switchgear duty, which we have identified in Section 4.

Possible Technical solutions1. The generator can minimise the fault current contribution from his plant through the careful design of

the connection to the PES network and selection of high impedance alternators and transformers. Additional impedance may also be introduced by installing series reactors between the generator and the PES network.

2. The PES may be able to reconfigure the distribution system to reduce the contribution from higher voltage networks or other generators. However, the scope for this may be limited by security of supply considerations.

3. The PES may reduce the fault infeed to their system by replacing existing transformers with higher impedance transformers, or by installing additional reactors. This is likely to be a costly option.

4. The PES may increase the rated duty of the switchgear on their system. Depending upon the type of switchgear that is installed on the system and the actual parameter that exceeds the rated value, the PES may be able to extend the switchgear rating. However, in most cases the connection of new generation causes a large increase in fault level that requires substantial switchgear replacement at one or more substations.

5. The use of a direct current (DC) link between the generator and the PES system effectively decouples the generator from the distribution system, so that the contribution to the system fault level is minimised.

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6. It may be possible to avoid fault level problems by connecting to a higher voltage system, although in some cases the connection of generation can result in excessive fault levels on lower voltage systems than the generator is connected to.

Possible Commercial and Regulatory solutionsThere are no commercial arrangements that can avoid the need for switchgear replacement, but commercial and regulatory measures may reduce the adverse impact that fault levels can have on the development of embedded generation projects. The present arrangements whereby the first generator that causes fault levels to exceed the permitted level, thereby initiating switchgear replacement, pays for the replacement works can, on occasions, make otherwise attractive embedded generation schemes uneconomic. The PES licence and the charging mechanisms that are used for load related development cater for the provision of system reinforcement that load schemes may require, but there is little to enable the PES to share the costs of reinforcements due to generation schemes. If a generator (the first comer) were to seek terms in the connection agreement whereby if a subsequent generator (second comer) were to be connected to the reinforced system that the first comer would be refunded part of the system reinforcement costs, then the risk would be carried by the PES. If the second comer refused to pay for the proportion of the reinforcement works then the PES would still be obliged to pay the first comer. This therefore removes any incentive for PES companies to offer such terms.

The determination of the basis for a charging mechanism that would allow the costs for generation related distribution system reinforcement to be shared between embedded generators will be a complex issue. It has been suggested that the production of a statement of charges similar to that produced by NGC for the connection to the transmission system could be prepared, but the number of possible connection designs that must be included for embedded generation appear to make this unfeasible.

8.4 Other IssuesWhere power system protection co-ordination considerations are a concern the PES can find a solution to the problem by either installing inter-trip circuits between the generator and other substations on the system, or by installing additional circuit breakers. Each of these options has a cost implication and the optimal for any given schemes will depend upon the site specific circumstances. In some circumstances additional protection may be required in order to decrease the time required to disconnect the generator in order to maintain system stability. If the generator is connected using a DC link then the rotating mass of the generator is decoupled from the rest of the system and transient stability is therefore not an issue.

In a number of cases embedded generators have experienced difficulties in providing a suitable earth impedance at the site, so that a prospective fault current can be dissipated in the ground without causing excessive voltage rises. This difficulty often results from the relatively compact generation sites being developed for small to medium sized gas turbines or CHP plants. In such cases, developers of embedded generation projects can ease the earthing difficulties by allowing as much land area as possible for the substation and station earth mat. If the calculated earth potential rises above acceptable levels under fault conditions then the earth impedance can be reduced by the

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installation of more earth conductors in the ground, use of special soil conditioning agents or by extending the physical dimension of the earth mat. If the earth potential rise or transfer potentials cannot be limited to below the desired value4 then the developer must investigate ways in conjunction with the PES to ensure that the earth potential rise will not poise a risk to either people or equipment.

4 The Electricity Association Technical Specification 41-24”Guidelines for the design, installation, testing and maintenance of main earthing systems in substations” prescribes a safe limit 430 V rms. or in the case of lines with fast acting protection that limit the fault duration to less than 200 msec 650 V rms.. These limits are based on the values laid down in CCITT (the International Telecommunications Union, Geneva) directives concerning the protection of telecommunication lines against harmful effects from electricity lines.

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9. CONCLUSIONS AND RECOMMENDATIONS

We have reviewed the ability of the electrical distribution networks in England, Scotland and Wales, to accept embedded generation. The review has been based upon information available in the public domain and the results of questionnaires sent to planning engineers at Public Electricity Supply companies and key industry stakeholders. As part of the study we have attempted to determine with as much precision as possible how much generation is embedded within the distribution systems, how this embedded generation has affected the operation of the distribution systems and to determine industries view of the potential uptake for embedded generation in the next 5 years. Included in this assessment is a commentary on what factors will influence the development of embedded generation together with a commentary on the technical, regulatory and commercial issues that may need to be addressed if embedded generation penetration is to continue to grow. We have also included an analysis of how the ongoing Review of Electricity Trading Arrangements (RETA) may affect the operation and development of embedded generation projects and how the separation of the supply businesses and distribution businesses within the PES companies may change the relationships that embedded generators presently have with the host PES.

9.1 Existing distribution systemsThe existing public electricity supply distribution systems were primarily designed for the connection of load customers rather than the connection of generation. In England and Wales systems that operate at a voltage of 132 kV and below are considered as distribution networks, whereas in Scotland systems operating at 132 kV are considered to be part of the transmission system. In all cases the 132 kV systems were designed to accept the connection of generation, as they originally performed a transmission function and could accept import as well as export. Power flows in the transmission circuits could therefore flow in either direction. 132 kV systems may therefore be considered as active networks and as such embedded generation can normally be readily accepted at 132 kV. Distribution systems operating at voltages less than 132 kV were designed to accept power flows in only one direction and may therefore be considered as passive systems, and may be less able to accept embedded generation.

There are three basic technical issues that the PES companies must consider first when assessing the connection of an embedded generation scheme; fault levels, voltage levels and thermal loading of equipment. The design of the present distribution systems has assumed that fault level contributions would originate from the higher voltage transmission systems, which provides only limited scope for increases due to large numbers of generators connected to the distribution systems. This is one of the fundamental difficulties that must be addressed if the penetration of embedded generation is to be significantly increased.

9.2 Existing levels of embedded generationAt present there is approximately 5.5 GW of generation embedded within the distribution systems in England and Wales. This represents approximately 7.5% of the installed generation capacity and 9.6% of the system maximum demand. In Scotland there is approximately 1.8 GW of embedded generation representing approximately 21% of the installed generation capacity and 31% of the systems maximum demand. Table 9.1 summarises the levels of embedded generation by PES region

Page 9.2

and shows that the level of penetration of embedded generation is approaching a significant proportion of the overall system capacity. This level of penetration is probably approaching the level beyond which there are implications for the overall integrity and operating efficiency of the integrated electricity system. The integration of significantly more embedded generation capacity should therefore be treated with due consideration of the impact on the system as a whole, rather than simply the part of the distribution system to which it is connected.

Table 9.1 Existing levels of embedded generation by PES network

PES Approximate level of existing embedded generation (MW)

Eastern 493East Midlands Electricity 748London Electricity 268MANWEB 712Midlands Electricity 224Northern Electric 266NORWEB 986SEEBOARD 250Southern Electric 482SWALEC 342SWEB 145Yorkshire Electricity 650Scottish Power 522Scottish Hydro-electric 1251.6Total 7339.6

9.3 Potential benefits/drawbacks for the connection of embedded generationThe potential benefits and drawbacks of embedded generation and their effects on the performance of distribution networks have been assessed in terms of system losses, the security of supply, avoidance of distribution system reinforcement, system control and safe operation of the system.

LossesAlthough from a superficial perspective it might appear that the effects of embedded generation would initially reduce losses on a distribution system this can not be generalised as the effect of each generator depends upon site specific considerations, including the magnitude and variation of local demand. The most important considerations are the capacity of the generator relative to that of the local distribution system, the location of the generation and the generation operating profile. A simplified analysis performed by M&M indicates that a generator rated to meet the minimum demand of customers close to its connection point will tend to reduce both the peak power losses and the overall energy losses on a distribution system. However, generation that is rated to meet the maximum network demand will tend to reduce the peak power losses but increase the overall system energy losses.Larger generation capacities may tend to increase peak power losses as well as

Page 9.3

overall energy losses. The experience of a number of the organisations consulted as part of this study, including M&M, is that many new embedded generation projects are being maximised in size to suit the network capacity rather than the local demand. If this experience is an accurate reflection of the general market conditions it is expected that overall distribution system losses will tend to increase as the penetration of embedded generation increases.

The calculation of Loss Adjustment Factors (LAFs) in determining financial charges for supplies and generators are intended to take changes in system losses into account. However, it is possible that for generators connected at voltages less than 33 kV the present methods of evaluating LAFs do not accurately reflect the impact generation has on system losses.

Security of SupplyThe generally applied distribution system security standard Engineering Recommendation P2/5 includes guidelines on the contribution that an embedded generator can make to the security of supply.However, this standard was written prior to privatisation when the majority of generation was under central control and when there was a much closer relationship albeit on an informal basis between customers with their own generation and the host distribution company. The distribution company could, therefore, reasonably expect embedded generation to be operated when required. Since privatisation generators operate to provide their best economic advantage, which may not correspond to the requirements of the PES. Unless there is a contract between the generator and the PES to guarantee that the generator will normally be available when required by the PES then it is unlikely that embedded generation can truly be considered to increase the security of supply.

The introduction of more equipment on a system introduces more components that could fail, and a reliability analysis may show that the presence of an embedded generator actually decreases the security of supply on a particular system.

Engineering Recommendation P2/5 is increasingly being considered as a minimum standard to be achieved, with pressure being put on the PES companies from the regulator, OFFER, to improve the quality of supply provided and to give customers a wider choice of supply security and energy source.

Avoidance of distribution system reinforcementAlthough the presence of an embedded generator may, in theory, be expected to contribute to the local network supply capability it is unlikely to be sufficient for the PES company to defer reinforcement of that system, unless the generator is prepared to enter a contact with the PES to guarantee its availability. This would normally require an individual generator to introduce redundancy into its plant at additional cost, typically 20-30% of the installed plant cost. However, if there are a large number of generators connected to 11 kV or 33 kV networks then this should allow reinforcement of the higher voltage networks to be deferred, as the effect of the embedded generators will effectively be seen as a reduction in the overall system demand.

System control and safetyThe operation of the UK electricity supply network with increased numbers of non-centrally despatched (or scheduled) generators could pose a risk of a supply failure unless appropriate measures are taken to cover the loss of a large number of these generators. This may result in the need for a greater number of large non-embedded generators being held in reserve. The installation of protection schemes to disconnect embedded generators when the there is a fault on the local

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system ensures the safe operation of the distribution system, but experience shows that there are many occasions when the generation is erroneously tripped. The main cause of such nuisance trips is the selection of settings for Rate Of Change Of Frequency (ROCOF) relays, and there is an ongoing exercise to monitor and revise the settings for these relays. The concern is that in the event of a major fault on the transmission system, resulting in a sudden reduction in grid frequency, a large number of embedded generators may be disconnected, thereby making the system conditions worse.

The connection of three phase generators to the distribution network will tend to improve the load balance on the PES network, with generators tending to act as a sink for negative phase sequence components in the supply due to either load imbalances or voltage distortions. The connection of single phase generators, either domestic CHP generators, domestic photo-voltaic cells or other DC sources will require a careful assessment to be made of the balancing of the loadings on the three phase distribution networks. It is possible that if domestic single phase generation develops to a large extent then a fundamental change in distribution network design could be required.

9.4 Experience of PES Companies dealing with embedded generationIn our discussions with the PES companies there were a number of concerns expressed regarding the future uptake of embedded generation schemes. At present the PES companies have generally noted an increase in their administration effort dealing with embedded generation schemes, increased difficulties in organising circuit outages for maintenance work and, in some cases, increased numbers of nuisance trips. A few PESs commented that they are aware that the presence of embedded generators had increased the losses on their system and most PES companies were concerned that they would face increasing load forecasting uncertainties in the future. In the present climate where the PES companies are resource constrained and receive only a limited amount of revenue from embedded generation, there was a general concern with the amount of engineering time and effort that was expended with applications for embedded generation schemes that often do not proceed to firm projects. The requirement to offer connections to a large number of developers in a limited time under orders of the renewable obligations was identified as a particular difficulty by some PESs.

Many of the PES companies felt that embedded generators contributed very little to the performance of the distribution system whilst taking an inordinate share of engineering and administrative resources. However, the growth of embedded generation is being managed competently by the PES companies and the development of procedures to deal with connection applications and general enquiries indicate the generally co-operative attitude that exists within the distribution companies.

9.5 The effect of the Review of Electricity Trading Arrangements (RETA)At the time of writing this report the RETA had not been finalised and there was insufficient information available regarding the proposed trading arrangements to enable a thorough assessment of RETA. However, any reform of the electricity trading arrangements will affect the commercial arrangements that embedded generators will enter.

The opportunity for renewable generators with a variable output to trade in the potentially lucrative short­term bilateral, or “four hour” market could be considerable, since with suitable technology it is feasible

Page 9.5

that a wind or wave energy generator could be able to accurately predict its output in such a time scale. The prospective operating arrangements for non-firm generation is not clear at this stage, but it is possible that their output could be traded in the “balancing” market. However, it is likely that NGC will set a minimum level of generation export capacity that can be traded in the balancing market, in order to enable them to operate the market effectively.

Fossil fuelled embedded generation generally establish bilateral energy supply contracts prior to their construction in order to secure favourable project economics. These generators should be able to adapt to the new market structure without too much difficulty. However, many embedded generation schemes are installed with a view to capitalising on the Triad benefits. It is not clear at this stage how these benefits will be treated under the new trading arrangements.

Many CHP schemes that are designed to match the steam demands of a site will have insufficient confidence in their long term power output in order to trade in the forwards and futures markets. These schemes will be better suited to trade in the short term bilateral market and so the new trading arrangements should increase the scope for CHP plants to maximise the revenue from their electrical output.

The possibility of trading in “security” should enable PES companies to make better use of embedded generation to defer system reinforcement providing suitable commercial arrangements can be agreed.

9.6 Potential growth of embedded generationThe overall conclusions arising from our analysis of the responses obtained from a wide range of stakeholders concerned with the uptake of embedded generating capacity are summarised below under the separate headings of renewable energy projects and Fossil Fuelled Projects.

9.6.1 Renewable energy projectsThe uptake of renewable energy projects in England, Scotland and Wales in the next five years is expected to be dominated by the contracted NFFO and SRO projects, although not all of these projects are expected to be constructed. We would, however, expect there to be some limited uptake of renewable energy projects outside of the NFFO/SRO mechanism, dominated by wind energy, some landfill gas, and with perhaps a very few municipal and/or industrial waste projects.

In total we would expect that an estimated 1.8 GW of installed capacity of renewable energy projects would be built within the next five years. It is anticipated that there will be a considerable spread of capacities distributed amongst the various PES regions. About half of the PES regions are expected to have an above average capacity. The five PES regions in which the highest capacities are to be expected are Eastern, Norweb, Scottish Power, Scottish Hydro-Electric and Northern Electric. A total installed capacity for these five regions is about 1.1 GW. The main obstacles to the uptake of non-wind renewable energy projects are the availability and cost of the fuel supply, the uncertainty associated with obtaining planing consents and the problems with raising private venture capital for such projects. The NFFO and SRO initiatives are having a substantial impact on the levels of uptake of renewable energy projects and the continuance of these initiatives will obviously be expected to maintain the stimulus required to achieve a considerable penetration of renewable projects.

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9.7 Fossil Fuelled ProjectsPredicting the near-term uptake of fossil-fuelled embedded generation plant (both CHP and non-CHP) in England, Scotland and Wales is extremely difficult, particularly at this time of substantial uncertainty and change in the Electricity Supply Industry.

Nevertheless, based on responses to a questionnaire circulated to industry stakeholders, known project developments recently awarded relevant Consents under the Electricity Act of 1989 and the Energy Act of 1976, and our own understanding of the state of the industry, we would suggest that between 1,500 and 2,750 MWe of fossil-fuelled embedded generation plant could be developed in the UK over the next five years.

Should there be strong government policy in the form of inducements or other short term measures, developers may find more projects become viable. It could be that such measures would produce on- target results but this is difficult to predict. It should also be noted that there would be an 18 months to 2 year lead time to develop, engineer and construct such plants which rules out significant increases in the short term. This will require an even greater rate of take up in year 2001 and beyond to meet the Government’s 2010 objectives.

Whatever the rate of development, we expect that most of this capacity will be in the form of gas fired CHP plant with power export. We do not anticipate significant growth in District Heating in cities, based on CHP and power export. Furthermore, most of these CHP projects will be developed in the traditional industrial areas of England, Scotland and Wales. It is in these regions that the impact on the local distribution systems will be highest.

9.8 Comparison of network capacity with Potential uptake of embedded generationOur analysis indicates that there should be sufficient network capacity to accept the predicted uptake of embedded generation, although in a number of areas there may be difficulty in accommodating the higher forecast levels of generation. Table 9.2 compares the network capability to accept new generation with potential uptake.

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Table 9.2 Comparison of network capability to accept new generation with potential uptake

Likely uptake ofPES Region Indicative renewable CHP non-CHP Total generation

network energy Capacity capacity capacitycapacity MW (MWe) (MWe) MWe

Eastern 910 264 10-150 3-40 277-454East Midlands Electricity 920 82 10-100 5-40 97-222London Electricity 390 23 10-100 5-100 38-223MANWEB 460 153 35-400 2-30 190-583Midlands Electricity 330 43 25-300 5-40 73-383Northern Electric 250 174 25-100 2-30 201-304NORWEB 620 275 10-300 2-40 287-615SEEBOARD 710 75 25-100 25-50 125-225Southern Electric 1270 61 10-100 25-100 96-261SWALEC 210 110 10-400 10-20 130-530SWEB 430 63 20-50 10-40 93-153Yorkshire Electricity 650 143 35-200 2-40 180-383Scottish Powerf 810* 217 35-200 2-40 254-457Scottish Hydro-electricf 110* 193 5-50 2-10 200-253

f These indicative capacities assume that there will be no transmission constraints imposed by the capacity of the Scotland-

England interconnector. In practice it is possible that access to the interconnector may limit the capacity of new generation that

can be connected in Scotland

* Assuming SRO contracted generation does not connect

9.9 Potential Solutions to difficulties experienced with Embedded generationIn section 8 we identified a number of technical, commercial and regulatory solutions to different types of difficulties encountered by the developers of embedded generation projects. The suggested solutions are summarised in Table 9.3.

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Table 9.3 Potential solutions to difficulties experienced connecting embedded generation

Difficulty Potential SolutionVoltage regulation Technical:-

1. Impose limits on generator operating power factors2. Install reactive power compensation equipment3. Reinforce existing circuits back to source substation4. Make direct connection to source substation5. Use power electronic interface to accurately control generator output to

control voltage at point of common coupling within specified range6. Connect to a higher voltage systemCommercial1. Restrict periods of the year when the generator can operate2. Allow generator to indemnify PES against any claims or losses arising from

voltage levels outside permitted rangeRegulatory1. Allow PES to schedule generation and allow NFFO/SRO generation to be

constrained, as appropriate to the local network2. Allow principals within Distribution Price Control mechanism to implement

appropriate technical solutions with penalty.Thermal loading Technical:-

1. Impose limits on generator operating power factor2. Install reactive power compensation equipment3. Reinforce existing circuits back to source substation4. Connect to a higher voltage systemCommercialRestrict periods of the year when the generator can operateRegulatory1. Allow PES to schedule generation and allow NFFO/SRO generation to be

constrained, as appropriate to the local network.2. Allow principals within Distribution Price Control mechanism to implement

appropriate technical solutions with penalty.Fault levels Technical:-

1. Design connection and generator to maximise the impedance between the generator and the PES system, minimising fault contribution.

2. Reconfigure the existing PES network to reduce the fault contribution from the rest of the system.

3. Increase the network short circuit rating, such as by replacing switchgear etc.4. Use a direct current link between the generator and the PES system to

effectively eliminate a fault current contribution from the generator.5. Connect to a higher voltage system.Commercial and Regulatory:1. Examine the existing arrangements to minimise any single generator

developers exposure to system reinforcement costs.2. Allow principles within Distribution Price Control mechanism to implement

appropriate technical solutions with penalty.

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9.10 RecommendationsIn order to encourage increased levels of penetration of embedded generation that will be required to reach the Government’s targets for electricity production from renewable and energy efficient sources we make the following recommendations. It is not intended that the order in which they are listed signifies any sense of importance or priority, which will need to be determined from further analysis.

• Formally separate the supply and Distribution businesses of PES companies.This is already due to be introduced following consultation on the Government’s Green Paper “A Fair Deal For Consumers”. The formal separation of the supply and distribution businesses should eventually remove concerns that distribution businesses give preferential service to their own supply customers rather than other Second Tier Suppliers or embedded generators.

• Enable PES companies to charge for the transport of electricity from a generation site in a similar way to the charges they make for the transport of electricity to demand customers.As a distribution company acts as a transporter of electricity it appears logical to charge all of its customers for transporting the electricity that they consume or sell. If a distribution company is able to generate revenue from a generator in the same way that it can from a demand customer then there should be a greater incentive to develop embedded generation schemes. In the medium to long term this may help to improve the relationship between developers and the distribution companies. This may also encourage distribution companies to invest in their network to enable more generation to be connected.

• Develop commercial measures that encourage PES companies to make the best use of embedded generation on their system.At present the income that a PES company can make under the tariff control is, in part, related to the value of its distribution assets. There is therefore likely to be more incentive to a distribution company to extend or reinforce its distribution system than to allow suitable embedded generation to defer system reinforcement. Development of new commercial measures that encourage PES companies to make the best use of embedded generation on their system would be expected to encourage the optimum use of distribution assets.

• Increase the incentives to PES companies to optimise distribution loss levels.The connection of generation that is rated to meet a local demand will tend to reduce system losses. If suitable incentives are given to distribution companies to optimise their loss levels they could use this to encourage the development of generation of specified ratings in appropriate areas. Assuming that these generation schemes are efficient or use a renewable resource this will further reduce CO2 emissions from the UK. •

• Review and update where appropriate Engineering Recommendation P2/5An updated version of the security standards should provide recommendations for system planners that reflect the present market conditions and advice on the contribution that embedded generation can make to the security of supply.

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• Replace the “must take” nature of future NFFO and SRO orders (or their equivalent) with a more flexible obligation that allows generation to be constrained under certain system conditionsA more flexible approach to the way in which the generation is accepted onto the distribution system from generators awarded contracts under NFFO and SRO orders should enable lower connection costs for renewable generation.

• Review the requirements of G59 and in particular encourage both PES companies and developers to consider alternatives to Rate of Change of Frequency relays for loss of mains protection.If the level of penetration of embedded generation is to increase it will become increasingly important that wide-spread nuisance trips of generation are avoided whilst ensuring that generation is disconnected quickly as required to ensure safe operation of the distribution system. •

• Allow PES companies to install higher fault rating equipment when upgrading their systemModern 11 kV switchgear rated at 40 kA is available for only slightly more cost than 26 kA equipment that a PES may consider appropriate for load related development. If the PES can recoup the additional cost of the investment in higher fault level equipment from embedded generators at a later date then this should encourage the evolution of the existing distribution infrastructure to a system that is capable of accepting more embedded generation. The cost implications to other customers already connected to the PES network who may have to replace equipment on their own systems due to increased fault levels should also be considered.

PB PowerMerz and McLellan Division

Appendix A Page 1 of 9

APPENDIX A

Scope of Work

4. PROGRAMME OF WORK

4.1 ACTIVITY DESCRIPTION

We propose to undertake the study work as a number of individual tasks as outlinedbelow:

1. Kick-off and mobilisationWe will commence the project with a kick-off meeting with ETSU to confirm the scope and programme of work, agree the contacts and visits to various organisations, and to agree the main areas/topics to be included in the questionnaires.

2. Preparation of questionnairesIn view of the need to obtain similar types of information/data on a number of different issues relating to embedded generation from each of the various organisations (PES companies, NGC, Trade Associations etc), we propose to prepare a series of carefully constructed and worded questionnaires. From our thorough appreciation of the technical issues involved and the sensitivity of the various organisations, we believe that we can construct the questionnaires in a way which has a very good likelihood of eliciting the information required. We will also compile a list of the appropriate personnel, at management level, within each organisation together with their mail/E-mail address, telephone and facsimile number. As far as the UK PES companies are concerned, Merz and McLellan have established long-standing contacts with their network managers and planning engineers.

3. Assessment of network limitationsWe will make direct contact with the network managers and planning engineers at each PES company, initially by phone and then by issuing the questionnaire developed in task 2, followed up by meetings at their offices as appropriate. The information required from the PES companies covers a wide range of topics (e.g. present levels of embedded generation, capacity for more generation, their network planning strategies, potential benefits) and it is therefore expected that the need for discussion meetings will almost be inevitable. We expect that, in general, the PES

MERZ AND MCLELLAN LIMITED M & M DocumenNo.33:00/PN06:392/99003

company will be aware of any limitations associated with their interface with the NGC transmission network and we therefore anticipate that our approaches to NGC will be limited to the issue of questionnaires, and possibly phone calls for confirmatory purposes.

For cases where the PES company identifies severe obstacles to the acceptance of new embedded generation we will attempt to identify the location and cause of the declared obstacle, by direct questioning. We will then endeavour to verify their assertions by carrying out our own simplified analysis of the network, with a view to assessing the capacity to accept new generation. We will make use of our extensive experience in analysing many parts of the UK distribution networks, which in many cases has included the assessment of the scope of the connection of generation.

The results of any work carried out on PES networks will be advised to the individual PES company for their comment prior to including the results in the report.

The results of this task will be a compilation of the responses obtained from the various approaches to the PES companies and to NGC.

4. Assessment of potential growth in embedded generationWe will assess the future growth of renewables, CHP and other embedded generation projects by reviewing the existing information, including historic trends and future targets, and by direct discussion with key players in these industries:

Published information sources, including the following, will be reviewed to assess forecasts on technology uptake:

• relevant Government Energy Papers;• the series of regional renewable energy studies published by PES

companies, ETSU and the DTI;• relevant European Commission publications funded through

programmes such as ALTENER, THERMIE B and the OPET network;

MERZ AND MCLELLAN LIMITED M & M DocumenNo.33:00/PN06:392/99003

• relevant Combined Heat and Power Association (CHPA) and ETSU CHP reviews.

Direct face-to-face or telephone discussions will take place with key players in different sectors associated with these technologies. These will include policy makers and strategic bodies, trade associations, and potential project developers and facilitators. Examples of such organisations include:

Policy makers and other strategic bodies:• ETSU and DTI (Energy Technologies Directorate) to, for example,

discuss the future prospects of the Non-Fossil Fuel Obligation (NFFO), which will continue to exert a strong influence over the short-term future of the UK renewable energy market;

• ETSU and the Department of the Environment (Energy Efficiency Office);

• the Non-Fossil Purchasing Agency - to discuss the success of the NFFO to date, to help in the assessment of the drop-out rate from recent and future tranches of NFFO.

Trade associations and other similar bodies:• the CHPA;• the Association of Electricity Producers;• renewable energy trade associations, such as the Landfill Gas

Association, the British Wind Energy Association, and British Biogen.

Potential project developers and facilitators:• banks and other financial institutions with significant portfolios a of

lending to, or investment in, sustainable and other small-scale energy schemes;

• existing developers of embedded generation projects;• relevant Contract Energy Management (CEN) companies;• BG Transco Ltd;• the PES companies themselves and, in particular, those with strong

interest in developing renewable energy projects, supplying CEN services or trading in gas.

MERZ AND MCLELLAN LIMITED M & M DocumenNo.33:00/PN06:392/99003

We would expect to make six face-to-face discussions with key organisations to be agreed with ETSU. The remainder of these interviews will be undertaken by telephone.

We would expect to receive sometimes conflicting views on the potential future uptake of some of these energy technologies from different players. These differing views will be acknowledged and, where possible, explained.

Our experience at both the strategic and project development levels, associated with our excellent contacts with banks, insurance companies, owner and operators, will enable us, we believe, to draw realistic conclusions. We will use our extensive knowledge of the field of sustainable and other small-scale energy supply systems to derive an informed analysis of the future, taking all views into account.

The deliverable from this task will be a comprehensive, broad assessment of the potential growth in renewable, CHP-based and other embedded generation projects in England, Wales and Scotland over the next few years. Informed commentary will be made with regard to the ‘technical’ potential for these energy sources, and a reasonable ‘commercial’ potential for their uptake, taking into account realistic commercial barriers to project success.

1. Assimiliation and analysis of collectedinformationFrom the information collected from the earlier tasks we will compare the industry prospects for growth with the capability of the distribution network. The overall and regional shortfall in network capability will be assessed.

The major technical causes of obstacles to the connection of embedded generation will be identified. Methods of overcoming such obstacles and allowing greater levels of embedded generation to be connected will be examined. Such methods will include technical, regulatory and commercial means.

MERZ AND MCLELLAN LIMITED M & M DocumenNo.33:00/PN06:392/99003

For presentation purposes we intend to use our in-house GIS facilities, particularly for displaying geographical and regional information collected and the results of the analysis work.

2. ReportingWe propose to produce a formal report on the findings of the work, initially as a draft for presentation to ETSU and DTI, and subsequently as a final report. Appropriate extracts of the draft report will be forwarded to the PES companies contacted during the study to elicit their comments prior to issue to ETSU.

The proposed report structure is as follows:-

1. Executive Summary2. Introduction3. Background

• Description of the distribution and transmission network in the UK including regional variations.

• Summary of the PES licence conditions relating to the connection of embedded generation.

1. The ability of UK distributionnetworks to accept embedded generation• Existing levels of embedded generation.• Capacity for more embedded generation.• Network planning strategies.• Limiting factors preventing the connection of new

embedded generation.

1. Technical benefits/drawbacksarising from embedded generation• Utilisation of distribution network assets.• Power losses.• Security of supply.• Need for distribution reinforcement.• Avoidance of distribution reinforcement.

MERZ AND MCLELLAN LIMITED M & M DocumenNo.33:00/PN06:392/99003

• Implications for NGC.

1. Potential for uptake forembedded generation technologies• Results of literature search and contacts with industry.• Broad assessment of future uptake.• Regional assessment of potential growth.• Commentary on technical and commercial potential.

1. Comparison of distributionnetwork capacity with industry prospects• Overall and regional shortfall in network capability.• Causes of shortfall.

1. Possible solutions to overcomeobstacles• Major technical causes of obstacles to the connection of

embedded generation.• Alternative methods (technical, regulatory or

commercial) of overcoming obstacles.

1. Conclusions

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APPENDIX B Page 9.1

APPENDIX B

Assessment of capability of PES networks to accept newembedded generation

M & M DocumenNo.33:00/PN06:392/99003

AppB

COMPANY: PBPower-Merz and McLellan Division CALCULATION NO.: DNR-001JOB NO.: 392-0003Page No.: 1

Client : ETSUProject : a Distribution Network Review

Section A : Defining the Calculation PackageWork Package Title :

Whole

Total number of pages in calculation : 8

Description of Calculation :

Determination of approximate capability of distribution networks to accept additional embedded generation

References:

1. Report on Distribution and Transmission Performance (1997/98) - OFFER2. Main Prospectus for The Regional Electricity Companies Share Offers (1990)3.

Software Used : Version Disc/File IdentifierInput Data Output Data

Prepared by rj Fairbairn Sign : Date :(Print Name) :Checked by Sign : Date :(Print Name) :Section B : Revision Details

Prepared CheckedRev Reason for Revision Sign Date Sign Date

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IntroductionThis calculation document describes the methodology employed to estimate, in very approximate and general terms, the ability of the distribution systems in the UK to accept new embedded generation capacity. The methodology consists of two stages. The initial stage produces a fairly crude estimate while the second stage refines the estimates to take into account more PES specific conditions that may limit the ability of a certain system to accept new embedded generation. The results of the initial calculation will tend to give results that are higher than the actual capacity of a PES network to accept new generation, as location specific constraints are not considered. However, as a general rule it may be assumed that the total capacity of embedded generation that a system may accept should not greatly exceed the system minimum demand. We compare the results of our analysis with the approximate values of PES minimum demands to assess the overall reasonableness of the capacities quoted. We further compare the our estimate of the generation capacity that could be connected on a kW/connected customer basis to further assess the reasonableness of the results.

Basic Methodology and AssumptionsA simplified diagram showing the typical arrangement of circuits originating from a Grid Supply Point is shown in Figure 1. The basic methodology is based on the following assumptions:-

• In a given PES area the ability of a rural distribution system to accept new generation will be broadly similar at each connection voltage

• In a given PES area the ability of an urban distribution system to accept new generation will be broadly similar at each connection voltage

• The connection of generation on one 11 kV network will not affect the ability of a neighbouring 11 kV network to accept new generation, where there is no normal 11 kV connection between them

• The connection of generation on one 33 kV network will not affect the ability of a neighbouring 33 kV network to accept new generation, where there is no normal 33 kV connection between them

• The connection of generation at 33 kV will reduce the generation that may be connected at 11 kV. As an approximate estimate we will assume that 1/20th of the generation capacity connected at 33 kV must be deducted from the capacity that may be connected at 11 kV

• There will be a limit as to the amount of generation that may be connected to a 132 kV group, and that in order to maximise the generation capacity that may be connected this generation is assumed to be connected close to the demand, i.e. at 11 kV or 33 kV.

• The maximum capacity of generation that could be realistically connected in practice will be less than the theoretical ability of the networks to accept this generation. This is due to a number of factors, including interactions between generators that may lead to complex protection schemes that make some projects economically unfeasible, and the connection/installation cost

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per kW of some generators means that the schemes are not feasible economically.

1,2 The basic statistics and parameters used for each PES are based oninformation presented in the oFFER spreadsheets that accompany the Report on Distribution and Transmission Performance (1997/98) and the information provided in the Main Prospectus for The Regional Electricity Companies Share Offers (1990).

By considering the overall equipment quantities for the PES company networks it is possible to produce an approximate estimate of the number of 33 kV and 11 kV primary substations, and also to estimate what proportions of the network may be considered as rural or urban systems. The equipment statistics indicate the number of transformers in each PES area and by assuming an average number of transformers per substation a deduction of the number of primary substations can be made. By considering the relative numbers of pole mounted and ground mounted transformers it is possible to estimate the proportion of networks that have a rural characteristic and the proportion that have an urban characteristic (pole mounted transformers are generally found only on rural distribution systems).

For each PES the following input information is required:-

(a) number of 132 kV/lower voltage transformers(b) number of 66 kV or 33 kV/11 kV or 6.6 kV transformers(c) number of pole mounted 11 kV or 6.6 kV/lower voltage transformers(d) number of ground mounted 11 kV or 6.6 kV/lower voltage transformers

Number of 33 kV BSPsFor the purposes of the present calculation we assume that (a) represents the number of 132/33 kV transformers, and that on average the number of 132/33 kV transformers installed at each BSP is a, where a is expected to be in the range 2 to 3.

Hence number of 33 kV BSPs = (a) ^ a

Number of 11 kV primary substationsWe assume that, on average the number of 66 or 33 kV/11 kV transformers per primary substation is p, where p is expected to be in the range 1.5 to 2.5. Hence

number of 11 kV primary substations = (b) + p

Proportion of urban and rural networksThe percentage of the PES system that can be assumed to represent rural and urban networks are given by

% rural = 100 x (c) + ((c)+(d))% and % urban = 100 x (d) + ((c)+(d))%

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By dividing the number of BSPs and primary substations in the proportions indicated it is possible to estimate the number of rural and urban type systems.

Network capability to accept generationFor each PES we estimate the typical ability of their network to accept embedded generation, both by connection voltage and by location. We shall only consider connections at 11 kV and 33 kV to maximise the potential generation capacity that can be accepted. Although generation could in practice be connected at 132 kV or 66 kV we have assumed for present purposes that the generation connected at these voltage levels will occur instead of at 33 kV or 11 kV. This assumption is based on the reasoning that all generation connected at voltages greater than 33 kV will be from synchronous generators, which will increase short circuit make and break duties at lower voltage switchboards (more than a 33 kV connected induction generator would to 11 kV switchboards). As generators connected to higher voltage levels will tend to have much larger capacities than those connected at lower voltages transient stability considerations may become much more important, which could also limit the generation capacity that could be connected.

The amount of generation that may be connected to a distribution system will normally be limited by one of two factors, fault levels or voltage regulation. In many areas, particularly those close to grid supply points and in urban areas, fault levels limit the capacity of generation that may be connected. In rural areas voltage control is often the main limiting factor, particularly in remote areas such as those found in Scotland, west Wales, cumbria and the south west. A typical PES may be able to accept the following capacities on the appropriate networks:

System voltage

Location 33 kV 11 kV

Rural 10 MW (1) 2 MW (3)

Urban 20 MW (2) 5 MW (4)

However, we have selected individual capacities for each individual PES based on discussions with network planning engineers in the appropriate organisations.

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The calculation is performed in two stages:-Calculations

Firstly 33 kV capacities are calculated:-

Capacity that can connect to rural 33 kV system =%rural/100*no 33kV BSPs *capacity that can connect to typical rural 33 kV BSP (1) (A)

Capacity that can connect to urban 33 kV system =%rural/100*no 33kV BSPs*capacity that can connect to typical urban 33 kV BSP (2) (B)

Then 11 kV capacities are calculated:-

Capacity that can connect to rural 11 kV system =%rural/100 * no 11 kV BSPs * capacity that can connect to typical rural 11 kV

primary (3)-(A)/20Capacity that can connect to urban 11 kV system =%rural/100 * no 11 kV BSPs * capacity that can connect to urban 33 kV primary (4)-

(B)/20

The above equations lead to a theoretical maximum capacity of generation that may be connected to the existing system. The results are shown in Table 2 under the column titled “Theoretical Generation”. In order to account for the interaction between machines on the network limiting the generation that is connected we shall assume the total generation that could be connected is a percentage of the theoretical maximum. This percentage is based on estimates of the proportion of generation that would be synchronous generators and induction generators, a typical number of generators that would connect to each network type and the cumulative effect of new generation on the system.

For each type of system, say urban 33 kV, rural 33 kV, urban 11 kV and rural 11 kV, a Interaction Adjustment Factor is determined. This factor aims to indicate what proportion of the total theoretical generation that will not be able to connect to the system due to its interaction with other users of the distribution system. The interaction may be caused by transient stability considerations, the cumulative effect of the reactive power flows caused by the generators and loads under start up conditions (e.g. motor start conditions) or it could be caused by other factors such as system protection, earthing and system operation.

We have estimated the following IAFs for the networks under considerationSystem voltage

Location 33 kV 11 kVRural 0.75 0.65Urban 0.65 0.5

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The above factors can be interpreted as an indication that, for example, 75% of the generation that could theoretically connect to a rural 33 kV system could actually be expected to be accepted in practice.

These factors are then applied to the number of 33 kV and 11 kV systems in question to obtain a capacity of generation that may not be connected. This, together with the levels of embedded generation already connected in a PES area, is taken away from the theoretical maximum to leave an estimate of the total capacity for new embedded generation which could be connected to a PES system. This figure is presented in Table 2 under the column titled “Rev Est 1”

Also included in Table 2 is a column headed “Crude Estimate”. This column simply assumes that 100 MW of new generation can be connected to each Grid Supply Point (GSP) that is in a PES company area (i.e. it does not include supplies taken from a GSP in a neighbouring PES area). It should be noted, however, that we have taken note of the views of PES companies where they have specifically indicated that a GSP has limited scope for connection of new generation capacity.

Table 2 also has columns indicating the maximum and minimum demands in each PES region. Although it is possible for power to be exported from a PES system to the NGC transmission system in most areas, it is likely that generation of such magnitude could not be accepted by the local networks and even if such capacity could be accepted this will require major protection modifications. The minimum demand is a further test of the feasibility of the estimates produced. The estimates produced are lower than the minimum demands, and as a further cross check the new generation per customer has been calculated. Given that the typical household consumes an average of between 1 and 3 kW, the numbers indicated appear reasonable.

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Grid Supply Point (Typically 400/132 kV)

132 kV

Bulk Supply Points (Typically 132/33 kV)

33 kV

Primary Substations (Typically 33/11 kV)

11 kV

Figure 1 Typical Arrangement if Circuits Originating from a Grid Supply point

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Table 1 Theoretical maximum capacity to accept generation by PES and circuit type

Generation acceptableDemand MW % rural % urban No 33kV No 11kV R 11kV U 11kV R33kV U 33kV

Eastern 7,516 56% 44% 90 863 2 5 10 25EME 5516 60% 40% 60 665 2 8 10 25LE 5284 0% 100% 30 291 3 5 10 15Manweb 4021 77% 23% 93 652 3 5 10 10MEB 5689.4 70% 30% 48 378 2 5 10 20Northern 3849.8 63% 37% 37 305 2 5 10 20Norweb 5342.2 52% 48% 67 684 2 5 10 20SEEBORD 4370 42% 58% 57 447 2 8 10 20Southern 6242 51% 49% 80 887 2 10 10 20SWALEC 2743.9 82% 18% 51 296 3 1 10 20SWEB 3065 76% 24% 44 521 2.5 5 10 20Yorkshire 5826 54% 46% 61 623 3 7 10 20HE 1550 94% 6% 52 780 2.5 8 10 20Scot P 4172 59% 41% 43 755 2 10 10 25

Total 65,187

Table 2 Adjusted and more realistic capacity to accept generation

Customers

Thousand

Demand

MW

Min

demand

MW

Basic

estimate

MW

Theoretical

Generation

MW

Crude

estimate

MW

Existing

Embedded

Generation

MW

Interaction

Adjustment

Factor

Rev est.

MW

kW/

customer

Eastern 3122 7,516 2,630 1,800 2,794 2,301 493 0.40 910 0.29

EME 2,300 5,516 1,931 1,100 2,643 2,766 748 0.40 920 0.45

LE 1,969 5,284 5,020 1,200 1,121 853 268 0.46 390 0.20

Manweb 1,380 4,021 1,407 1,200 1,957 1,244 712 0.37 460 0.33

MEB 2,200 5,689 1,991 1,100 1,109 885 224 0.38 330 0.15

Northern 1,442 3,850 1,347 1,700 934 668 266 0.39 250 0.17

Norweb 2,190 5,342 1,870 1,500 1,894 1,554 340 0.40 620 0.28

SEEBORD 2,014 4,370 1,530 1,200 2,015 1,765 250 0.41 710 0.35

Southern 2,650 6,242 2,185 1,400 3,633 3,151 482 0.40 1270 0.48

SWALEC 970 2,744 960 900 943 601 342 0.37 210 0.22

SWEB 1,316 3,065 1,073 800 1,286 1,141 145 0.38 430 0.33

Yorkshire 2,060 5,826 2,039 2,400 2,283 1,633 650 0.40 650 0.32

HE 640 1550 542.5 4100 1572 321 1251 0.36 110 0.17

Scot P 1,800 4172 1460.2 4100 2565 2,043 522 0.40 810 0.45

*This figure includes 132 kV connected generation capacity indicated in the Scottish Power Seven Year Statement for 1998/99

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APPEND IX C

Page 1 of 7 Pages

APPENDIX C

Questionnaire responses from Industry Stakeholders

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C. The Developers View of Embedded Generation

General

This section of the report gives an overview of the responses to the questionnaire not already discussed in Section 6. Where applicable we include our own observations to each topic and raise as conclusions, points which we believe to be significant, suggested areas for investigation and changes which may increase the commercial viability of embedded generation projects. These items together indicate potential for increasing the uptake of schemes.

The responses to questions B.7 onwards are covered here. Questions B.7 to B.11 covered fossil fuel projects. All respondents were invited to respond to questions C.1 to C.8 and in addition there was a catch all question, under the heading Other Issues.

Questions A.1 to A.6 and B.1 to B.6 were discussed in Section 6 of the report as they are related to the likely uptake and geographic disposition of renewable energy projects and fossil fueled projects respectively.

Responses and Observations

Question B.7 asked respondents whether from their knowledge of the industry, of the projects that fail, what have been the principal reasons (e.g. planning, licensing, fuel price, low energy revenue, technical connection issues, commercial connection issues).

There was a wide range of factors raised by respondents and despite the low number of responses, a pattern is apparent. This is of low benefits from CHP and difficulties encountered by developers. The indicated high cost of plant, low energy revenues, uncertainty over gas prices (and ratio of gas : electricity) are key here. The potential for savings can be too low to justify the capital expenditure. The difficulties encountered by developers may cause considerable frustration and introduce a great deal of uncertainty to the project development process but will not be a first order cost impact on the anticipated cost per kW of power.

Question B.8 asked whether respondents expect these reasons to change over the next 3-5 years and if yes, how they will change.

The respondents acknowledge Review of Electricity Trading Arrangements (RETA) and other market forces but none foresees an improvement over the next 3 to 5 years. Whilst some or all respondents may wish for inducements or other government led change, none appeared to expect this or offer this as a prospect for change.

Question B.9 asked, whether, where gas firing is envisaged, has selection of interruptible gas tariff required significant increases in plant redundancy and thereby cost. We further asked respondents to indicate approximate percentage impact.

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There was an unexpected, wide range in cost estimates for back up fuel to cover gas interruption from 10% to 35% with one very low estimate of 1 to 1.5 %. From our experience of this type of project, these additional costs appear highly significant and reduce the overall benefits of CHP for each scheme.

Question B.10 asked whether for CHP plant that is sized to meet on-site load, are capital costs disproportionately high and does this reduce project development success rate. Further, would such projects be more likely to succeed if they were larger and exported more electricity?

All but 2 respondents (1reply and 1 abstention) think that restricting plant to heat or power match is a constraint and that power export is important to the financial justification of projects. Larger plant benefits from lower cost per kW.

This reinforces the responses to question B6 and we believe this to be a major consideration. If government states clearly that export is acceptable, more projects will be viable and developers will be able to proceed with a higher degree of certainty than hitherto. Confidence will grow as more projects gain sections 14 and or 36 consent. We understand that this may require a qualification that overall project efficiency is to be 70% or above

Question B.11 asked whether for fossil-fuelled CHP, District Heating with prospect for additional revenues is seen as a significant factor in improving take up.

Whilst District Heating is, on paper a good base load for heat from CHP, practical issues were raised by respondents. Key items are higher risk than industrial CHP, infrastructure costs, pressure on land for sites and heat customer reluctance to commit prior to commissioning. In our view, DH with CHP may be the biggest gap between overall government plans for CHP and industry practicalities.

Small schemes will continue to be installed for individual hotels, hospitals, offices or other suitable loads. As time passes, the best opportunities will be taken up and the rate of installation may slow down. Even without a slow down, a large number of small schemes is unlikely to meet the targets. Without major change, designed to encourage larger schemes, targets will not be met.

Section C comprised general questions for all embedded projects. These were aimed primarily at project developers but we invited others to respond if they have views or comments that they would like to make.

Question C.1 explored Grid Connections and we asked respondents whether they found regional variation (PES to PES or within a PES) in reinforcement charges, revenues for power export, or identified any other geographical factors which had a first order impact on project viability.

The responses to this question ranged from no variation PES to PES to nominating a PES. No consensus is evident and the responses are of interest more for the factors raised than any pattern. Key items are:

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time delay for REC to provide information variation in revenue for export uncertain triad sharingcharges may include for reinforcement deeper than necessary high connection charges, particularly in remote areas.

We do not believe that in general these issues prevent development of otherwise viable schemes.

Question C.2 referred to the NGC 7 year statement which identifies location and scope for cost- effective generation. We asked whether respondents believe that similar public domain information on the preferred locations for embedded generation within distribution networks would increase project development success rate.

The mix of responses here indicated that this a complex issue. One respondent reinforces the “theoretical” advantage, another indicates that there are unlikely to be host sites with a business need adjacent to good points in REC systems. REC reluctance is also suggested.

This was a surprising response as in theory, the publication of data showing good locations for embedded generation would be a win / win for REC and developer.

At present, developers find prospective clients then investigate the economics, including infrastructure issues. Where the developer is part of a REC, this must be done without access to distribution company records. RECs know where they would like reinforcement or local generation and will have some local knowledge of industrial or other large users.

Marrying the two elements of information will not be easy but we suggest that this or other means to capitalise on the apparent synergy may prove fruitful.

Question C.3 asked whether clearer and simpler connection procedures and more guidance on the interactive nature of negotiations with the host PES would assist project development.

Again, a mix of responses, for and against clearer connection procedures in the ratio 7 : 3 (with 2 not answering). On balance, changes to procedures appear to be desirable rather than essential for project success.

Question C.4 asked respondents to comment on the overall attitude and degree of co-operation of the PESs, particularly whether benefits to the distribution system are passed on by reduced connection charges.

There was a variety of responses ranging from good experience, no problems, difficult to quantify to problems having been encountered.

The extremes of reply here are perhaps more significant than the individual replies but generally highlight the problem of entrenched attitude rather than spirit of partnership or

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mutual benefit. We believe that this should be explored and means identified to reduce the scale of problem. Whilst not a primary economic issue, both parties must be certain that benefits and costs are transparent.

Question C.5 asked respondents, in cases where electricity is required for a process, whether top-up, use-of-system and standby charges had a first order impact on project viability and if so, whether this can be quantified in p/kWh.

The values for standby capacity charge are as expected and the point is well made that the energy does not have to be provided by the host REC. Some developers may be in a position to negotiate good deals or even provide from within their own portfolio.

The reference to RETA is also pertinent and we note the observation that as currently perceived, this may exacerbate the situation.

One respondent notes that connection / reinforcement costs are a more significant impact than standby capacity charges. We would suggest further work in this area to establish whether this is more related to the uncertainty than the relative values.

Question C.6 explored the impact of Planning and Consents on recent project development and asked respondents to comment on:

Planning Permission Integrated Pollution Control Section 14 Section 36 Section 37

Again, a range of responses but with some interesting individual observations which are noted below.

R4 notes a distinction between planning permission for CHP and renewables and finds the IPC process is becoming more difficult. R6 notes the delay in the section 14 process which brings problems to developers.

The responses on sections 14 and 36 are naturally historical and time will indicate whether there will be significant improvements. Only 1 response indicates problems with section 37 and would be useful to establish whether geographical factors impacted the particular projects.

Question C.7 explored the Electricity Market and asked respondents whether further electricity market restructuring such as the 4-hour market will assist or hinder project success rate.

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Whilst some responses are positive regarding restructuring, the more common view is of uncertainty and the belief that change may not be for the better. We believe that uncertainty is a larger obstacle to project development than adverse but quantifiable change.

Question C.8 explored Gas Issues asked whether gas connection, system reinforcement or gas re­compression issues impacted project viability and if so, whether this can be quantified.

The costs associated with gas connection and re-compression for GT appear to be quantifiable albeit in some cases significant to project economic viability. If difficulties with dealing Transco are noted this may be frustrating or add time to the development phase but should not preclude a viable scheme from succeeding.

The benefits of Transco policy will no doubt filter through on some future projects with a possible increase in clients prepared to accept single fuel plant and the inherent savings.

The final question was relatively open, entitled Other Issues. This asked respondents to state their views on key issues or give overview of any other factors which would assist project development success rate in their market niche. The question included reference to factors such as credits for efficient or non-fossil generation, carbon trading, power sales co-operatives or system related incentives as a guide to areas of interest.

We had included this catch-all question to poll for other factors or ideas which could be developed further. If respondents have such views, they were not forthcoming in their replies.

The responses include reference to the Marshall Plan and a desire for subsidy for “green power” by this or other means, a need for increased certainty for consents and reference to government policy impacting the industry.

Conclusions

For fossil-fuelled embedded generation, respondents cited reasons for project failure which may be categorised as administration difficulties, project development uncertainties or hard economic factors. Administration difficulties cause frustration and may add time and cost. Project development uncertainty may cloud an otherwise sound economic case to the point of project failure.

Fuel price does not appear to be a major factor whereas uncertainty and low revenue from energy sales does. Whilst gas is the logical fuel choice at present market prices, cost of dual-fuel back up to gas interruption adds significant cost per kW hour generated. A number of other factors are raised which together can be regarded as showing that the developers find marginal benefits for CHP in a number of projects. This is reinforced by the strong response that for economy of scale benefits to accrue, plant should be over sized relative to the true site heat match.

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District Heating is sound in theory but in fact respondents do not find it viable due to complexity and uncertainty.

The responses to part C of the questionnaire were mostly applicable to fossil fuelled embedded generation with some input on renewables. The grid connection and consent issues are generally seen as administrative problems rather than major obstacles.

It remains to be seen whether recent fossil fuelled CHP consents will open a floodgate but we suspect that project economics will remain as the main limiting criterion for individual renewable and fossil fuelled project success or otherwise. More significant for fossil fuelled projects are gas connection and re-compression with electricity top up and use of system charges respectively 0.5 p/kW h and 0.3 p/kW h.

The low price of recent NFFO and SRO orders was not raised as a particular issue nor was it cited as a reason for potential project failure. The fixed term and price certainty for power sales contracts in these cases may enable lower price per kW hour than for CHP with much less certain power sales.

The questionnaire sought respondents views on positive issues which could assist them. The replies were disappointing in this respect with no initiatives or responses to the items raised in the questions. In particular, we expected more support for tax credits (Marshall), power sales co-operatives for CHP (as for expired NFFO), district heating, PES data on preferred locations, simpler connection procedures. The relaxation of Transco reinforcement policy was only acknowledged by 1 respondent.

Looking to the future, the current perception is that there must be positive measures to accelerate growth in project development but an underlying fear that RETA and slowing of the economy will cause the opposite. There is no confidence that the Offer studies, Marshall Plan, RETA, downward pressure on electricity prices (especially relative to gas) and government policy will combine into workable incentives for Renewables and CHP.

We believe that without major change, fossil fuelled CHP targets will not be met. The following tangibles must be addressed to meet Kyoto or UK 2010 objectives:

Control RETA process to protect renewables / CHP from negative aspects Introduce appropriate incentives or subsidies for green generation Clarify CHP criteria for consent Guarantee early and fast procedure for project consent

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