This 2006 Great Britain Seven Year Statement (GB SYS) is the second such Statement to be produced since the British Electricity Trading and Transmission Arrangements (BETTA) came into effect on 1 April 2005.
With the introduction of BETTA, National Grid, in its role as Great Britain System Operator (GBSO), is required to produce a single GB SYS covering the whole of Great Britain on an annual basis. The two Scottish transmission licensees are required to assist National Grid in preparing the Statement pursuant to their licence obligations
This 2006 GB SYS presents a wide range of information relating to the transmission system in Great Britain including information on demand, generation, plant margins, the characteristics of the existing and planned GB transmission system, its expected performance and capability and other related information. Amongst other things, this information should enable existing and prospective Users of the GB transmission system to evaluate opportunities for making new or further use of the GB transmission system.
This Executive Summary provides a brief description of some of the key points contained in the main text. For a more complete picture on any particular topic, including the terminology used, the reader is advised to consult the relevant section of the main text. In particular, readers unfamiliar with BETTA are advised to refer to the chapter in the main text titled "Market Overview" Market Overview, which provides a high level overview of BETTA and also reports on related issues such as governance, institutional and contractual arrangements. That information is neither repeated nor summarised in this Executive Summary.
The data and results presented in this summary are correct as at 1 December 2005 (the data freeze date) and do not include changes included in the Quarterly Updates which are issued on a regular basis (at intervals of approximately three months). The first Update will be issued soon after the main Statement and will report on changes that have occurred since the data freeze date.
The main forecasts of electricity demand to be met from the GB transmission system presented in this Statement are based on information submitted by Customers who take (or propose to take) electricity from the system. However, for comparison, our own view of demand growth is also included. Unlike the 'User' based forecasts, which include details of individual Grid Supply Point demands, the NGET forecasts are national projections for Great Britain.
All demand forecasts are in respect of the Average Cold Spell (ACS) winter peak and include transmission losses, distribution losses and exports to External Systems across External Interconnections. The forecasts are in respect of the time of simultaneous peak on the GB transmission system and are unrestricted (i.e. take no account of demand response/management by customers). This prudent approach in transmission planning is made on the basis that demand response/management by customers cannot be fully relied upon to be enacted at peak times.
Peak unrestricted demand on the GB transmission system in ACS (average cold spell) conditions, as projected by the system 'Users', increases from 62.8 GW in 2006/07 to 68.6 GW by 2012/13. This represents a growth rate of 1.3% per annum as indicated in Figure E.1 . Figure E.1 includes recent outturns together with the current User forecasts of ACS peak demand on the GB transmission system.
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Actual GB peak demand in the winter of 2005/06 (at 60.3GW) was 800MW higher than in the previous winter. Correcting historical actual demands to ACS conditions eliminates the weather effects and gives a better indication of the underlying pattern of annual peak demand. Correcting winter weekday demands to ACS conditions yields a provisional 'unrestricted' peak of 62.8GW in 2005/06, reflecting zero growth on the 2004/05 ACS outturn.
We have also prepared our own 'base' forecast of peak demand and annual electricity requirements, together with 'high' and 'low' transmission system demand scenarios. These are based on combinations of favourable and adverse developments for factors such as economic growth and embedded generation. In reality, future demand is likely to fall well within the resulting ranges. Whilst the majority of the analyses and studies contained in this Statement have been prepared on the basis of the demand forecasts provided by our customers, our forecasts are included as supplementary information and reflect our views on possible outcomes based on specific assumptions.
Figure E.2 compares our base, high and low demand forecasts with the User based forecasts. Under the 'base' forecast the ACS peak demand increases by 0.6% pa, from 62.8GW in 2005/06 to 65.4GW in 2012/13.
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When compared with our base projections, the Users' forecasts show stronger growth (illustrated in Figure E.2). In submitting their forecasts, 'Users' are not required to provide information on their background assumptions. Possible reasons for the transmission system demand differences include alternative views on economic prospects, the growth of demand met by embedded generation.
In general, the level and location of generation remains the major factor in determining the need for transmission reinforcements. However, in some areas (e.g. where demand exceeds generation) it is demand that can exert the greater influence and as such there is an increasing need for accurate demand forecasts in terms of both level and location.
Chapter 3 presents information on all sources of generation, which are used to meet the ACS Peak GB Demand. Accordingly, this chapter reports on all power stations directly connected to the GB transmission system, whether they are classified as Large, Medium or Small, all directly connected External Interconnections with External Systems and all Large power stations, which are embedded within a User System (e.g. distribution system).
In recognition of the uncertainties associated with the future, unless otherwise stated the information presented relates to existing generation projects and those proposed new generation projects, which are deemed most likely to proceed to completion. Accordingly, proposed future projects, which are classified as "transmission contracted" are included. These would include projects within GB Offer "Group A" and some projects within GB Offer "Group B". Both these terms are defined in the Glossary.
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Figure E.3 illustrates the increase in generation capacity of plant since 2000/01. Notified reductions in capacity from plant closures and from plant being placed in reserve have been taken into account.
A feature of the future commissioning stream,shown in Figure E.3, is the relatively high level of activity in relation to capacity increases (9.1GW) indicated for the year 2008/09. Some 2.2GW of this increase is attributable to new plant in Scotland (2.1GW of on-shore wind farms and 0.1GW of hydro) and some 6.9GW is attributable to new plant in England and Wales (4.2GW of CCGT plant, 0.6GW due to stage 1 of the Netherlands Interconnection and 2.1GW of off-shore wind). It is worth remembering, however, that, in the event, there may well be a more graded increase in activity over a number of years. The fact that a project is currently 'transmission contracted' is not an absolute guarantee that the project will proceed to completion since there are other factors, which may also influence that outcome (e.g. financing, fuel prices, consents etc.).
Figure E.4 shows the generation mix from 2006/07 to 2012/13 and includes both the existing and proposed new transmission contracted plant.
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The aggregate Transmission Entry Capacity (TEC) rises from 76.3GW in 2006/07 to 94.5GW by 2012/13. This is an increase of 23.8% or 18.2GW over the period from the 2006/07 winter peak to the 2012/13 winter peak. This net increase is made up of the following:
The largest proportion of the overall increase is due to CCGT plant at 53.4% with CHP accounting for a further 3.3%. The second largest proportion of the increase is due to Wind with on-shore wind accounting for 27% and off-shore wind accounting for 18.2% of the increase. On this basis, the capacity of CCGT plant would overtake that of coal in 2008/09. By 2011/12, CCGT capacity would exceed coal capacity by 4.6GW and account for 35.6% of the total transmission contracted installed generation capacity. Similarly, wind generation capacity (both on-shore and off-shore) is set to rise to 9.4GW by 2012/13. These capacities do not include the embedded Medium and Small generation and embedded External Interconnections with External Systems. The capacity of such embedded generation sources is the subject of Embedded and Renewable Generation.
It should be remembered that the above figures reflect the current contracted position and take no account of future uncertainty. As mentioned previously, it is reasonable to suppose that further new applications for power station connections will be received and, at the same time, some existing contracts may be modified or terminated and some existing power stations will close.
The focus of this chapter is on embedded Medium and Small power stations and embedded External Interconnections with External Systems. Embedded Large power stations are reported in the previous chapter.
Much of the existing and future embedded generation is either in the form of combined heat and power (CHP) projects or in the form of renewable projects. This chapter considers these two types of generation source, their growth, the implications for the GB transmission system and other related issues. In so doing, the chapter also reports on large non-embedded renewable sources of generation (e.g. Wind farms).
National Grid recognises the importance of climate change issues and that the government's targets for growth in CHP and renewable generation are likely to lead to a continuing growth in embedded generation. It is important for National Grid to play its part in facilitating this growth by ensuring that any transmission issues arising are appropriately addressed. At present, no insurmountable transmission problems associated with accommodating new embedded generation projects are foreseen. Indeed, the properties of the interconnected transmission system are such as to facilitate embedded generation growth regardless of location.
Nevertheless, this does not preclude the potential need for reinforcements to the GB transmission system, the extent of which would be a function of the system location of the new plant. For example, the extent, and therefore cost, of GB transmission reinforcement would be a function of the volume of off-shore wind located off the England and Wales coast or on-shore wind located in Scotland.
National Grid's responsibility in the Balancing Mechanism is to balance generation and demand and to resolve transmission constraints. The persistence effect of wind and the expected significant diversity between regional variations in wind output means that, while the balancing task will become more onerous, the task should remain manageable. Provided that the necessary flexible generation and other balancing service providers remain available, there is no immediate technical reason why a large portfolio of wind generation cannot be managed in balancing timescales. However, balancing costs would be expected to rise in line with the wind portfolio. We have estimated that for a case with 8000MW of wind needed to meet the 10% renewables target for 2010, balancing costs can be expected to increase by around £2 per MWh of wind production. This would represent an additional £40million per annum, just over 10% of existing annual balancing costs although it is important to highlight that this figure was calculated before a number of recent developments in market rules (e.g. CAP047 Response Pricing) and increases in underlying market costs (e.g. recent rises in generation fuel prices).
In the longer term, we do not think it likely that there will be a technical limit on the amount of wind that may be accommodated as a result of short term balancing issues but economic and market factors will become increasingly important.
This chapter brings together information on generation capacity and forecast ACS unrestricted peak demand from previous chapters and examines the overall plant/demand balance on the GB transmission system by evaluating a range of potential future plant margins. The chapter concludes with a brief report on the related issue of gas and electricity market interaction.
It is emphasised that none of the plant margins presented in this chapter is intended to represent our forecast or prediction of the future position. The primary purpose is rather to provide sufficient information to enable the readers to make their own more informed judgements on the subject. The plant margins presented have been evaluated on the basis of a range of different backgrounds.
In view of the uncertainties, relating to the future generation position, three generation backgrounds have been considered. Each has been selected in recognition of the different level of certainty relating to whether the proposed new transmission contracted plant will, in the event, proceed to completion.
This background includes the existing generation and that proposed new generation for which an appropriate Bilateral Agreement is in place. This would include projects within GB Offer "Group A" and some projects in GB Offer "Group B". The fact that a generation project may be classified as 'contracted' does not mean that the particular project is bound to proceed to completion. Nevertheless, the existence of the appropriate signed Bilateral Agreement does provide a useful initial indicator to the likelihood of this occurring.
A second useful indicator is whether plant has already been granted the necessary consents under Section 36 (S36) of the Electricity Act 1989 and Section 14 (S14) of the Energy Act 1976. This background includes all existing plant, that portion of plant under construction that has obtained both S36 and S14 consent where relevant, and planned future plant that has obtained both S36 and S14 consent where relevant. Any 'contracted' generation not already existing that requires S36 and S14 consent but has not obtained both is excluded from this background.
This background is essentially the same as background 2 but excludes all future generation plant not yet under construction.
Figure E.5 compares plant margins derived from the customer based demand forecast with those derived from our own base view of future demand growth for the above three backgrounds; giving six sensitivities in all.
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The main text considers a number of other factors, which can influence the value of plant margin. These include: as yet un-notified future generation disconnections (closures); the possible return to service of previously decommissioned plant (or the return to service of plant with TEC currently set at zero). The potential effect on the apparent plant margin of the sterilisation of generation capacity by virtue of its location behind a transmission constraint is also considered as is the appropriate contribution towards the plant margin of generation output from wind farms.
To illustrate this last point, additional plant margins have been calculated for a range of assumptions on the availability of wind generation capacity at the time of the winter peak. Nevertheless, it should be remembered that such a range is quite arbitrary in this plant margin context. Figure E.6 displays plant margins for wind capacity availability assumptions of 80%, 72%, 60%, 40%, 20% and 0%. The SYS background (i.e. with an inherent 100% wind capacity assumption) is also included for comparison.
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The margins displayed in Figure E.5 and Figure E.6 should not be taken at face value. The net result of the various uncertainties associated with the future plant/demand position is to produce a wide range of possible outcomes. In recognition of this, we have developed our own view of the likely developments into the future, which is considered alongside the SYS based backgrounds when undertaking our investment planning processes.
The requirements placed on the transmission system depend on the size and geographical location of both generation and demand. However, it is generation that tends to exert the greater influence.
Figure E.7 summarises the Scotland (SHETL), Scotland (SPT), North, Midlands and South disposition of all transmission contracted generation (both existing and planned) in the years 2006/07 and 2012/13.
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However, more importantly, it is the generation actually used in meeting the demand on the day, which determines the power flows at any given time. The 'GB Generation Ranking Order', which is explained in GB Transmission System Performance, is used to determine which generation is operated for the study purposes of this Statement.
By way of illustration, Figure E.8 shows the Scotland (SHETL), Scotland (SPT), North, Midlands and South disposition of installed generation (also shown in Figure 3.4) together with the regional ACS peak demand disposition. In both 2006/07 and 2012/13, the installed generation in Scotland (SHETL), Scotland (SPT), North and the Midlands exceeds demand, in some areas by a substantial amount. In the South, there is a more even balance in both years with demand exceeding installed generation in 2006/07 and this being reversed by 2012/13. Superficially, this would imply only modest but increasing power transfers across the system.
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However, when the generation expected to be used to meet the demand is considered, a different picture emerges as illustrated in Figure E.9. Again generation in Scotland (SHETL), Scotland (SPT) and the North exceeds demand in both years. However, in the Midlands and South much of the generation becomes non-contributory (i.e. not used in meeting the demand) such that the demand exceeds generation, by a substantial margin in the South, in both years; implying higher power transfers from the northern parts of the system, through the Midlands to the South. The power transfers at the time of peak under the 'SYS background', are reported in more detail in GB Transmission System Performance.
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There are a number of boundaries on the GB transmission system that serve to illustrate the performance of the system. The main text of this Statement introduces 17 critical boundaries which, amongst other things, are used in determining the need or otherwise for transmission system reinforcement/investment. These boundaries relate to 17 SYS zones, which are also identified in the main text.
It should be noted that the 17 boundaries used in this Seven Year Statement serve as useful indicators of system capability but the apparent capabilities derived are dependent on the precise generation and demand background used. Table 7.3, of the main text, provides a useful reference overview of the power transfers, under the 'SYS background', across each of the 17 main system boundaries. The transfers are based on the expected contributory generation plant rather than installed capacity.
However, it is recognised that the 'SYS background' does not necessarily represent the most likely outturn. There is uncertainty associated with the demand forecasts and in particular with future generation developments. These factors will affect future power transfers, transmission system capabilities, the need or otherwise for transmission system reinforcements and the opportunities for making new or further use of the transmission system.
In view of this, we have presented the 'SYS background' transfers and capabilities against the backdrop of a range of probabilistic transfers. These probabilistic transfers reflect our current views on the likelihood of the various generation and demand uncertainties. This presentation is intended to provide a more meaningful view of future transfers, promote a better appreciation of the future uncertainty we face in planning our system and enable the reader to make more informed judgements on the opportunities for making new or further use of the transmission system.
The main text of this Statement (see Transmission System Capability) includes probabilistic transfers for all 17 boundaries. As an example, the results for two key boundaries are given in Figure E.10 and Figure E.11. With the predominant high north to south power flows seen on our system, these two boundaries (i.e. the SPT to NGET boundary and North East and Yorkshire boundary) are particularly important.
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Figure E.10 and Figure E.11 show the boundary transfer (SYS Transfer), required capability (SYS Required Capability) and actual capability (SYS Capability); all derived on the basis of the 'SYS Background'. These are displayed against a backdrop (shaded areas) of our current view of the probable transfer range.
The required capability is simply the boundary transfer enhanced by an allowance for security (referred to as the Interconnection Allowance) to take some account of variations in weather, generating plant availability and demand forecasting error either side of the boundary.
For the SYS Capability, two types of capability have been analysed: thermal and voltage. Where the voltage capability is less than the thermal capability, the voltage capability is given. The boundary capability may be further reduced at other times for stability reasons.
Turning now to the probabilistic transfer ranges (shaded areas); the darker shaded central band extends (on the vertical axis) from the 25th to the 75th percentiles of the range of probabilistically derived transfers, and thus includes 50% of all such transfers across the boundary at the time of system peak. The wider area, encompassed by the lighter shaded bands runs from the 5th to the 95th percentile and thus, together with the dark band, includes 90% of transfers. The remaining 10% lie outside the shaded range. The fan of probabilistically derived transfers can be compared with the deterministic planned transfer for the single deterministic SYS background.
It does not follow that the probabilistic transfer arising from a background considered to be likely will necessarily be captured within the envelope range shown on the diagram. Nor does it follow that all the most commonly occurring transfers have highly probable backgrounds. In our Generation Uncertainty Model (GUM), all backgrounds are equally probable. Nevertheless, the range of transfers displayed in the fan diagram does provide a very useful indicator of the most probable future planned transfer across the boundary given the possible combined effects of the various sources of generation and demand uncertainty. GUM can then be interrogated to reveal the details of any background underlying any transfer (point on the fan diagram) for further detailed analysis.
In the example given in Figure E.10, the SYS Planned Transfer lies above the 50th percentile in the probabilistic range of Planned Transfers while the SYS capability is in the lower part. There is hence a chance of lower peak flows than suggested by the SYS background; however, significant reinforcements will nevertheless be required in the very near future to facilitate even the lower parts of the range of probabilistic transfers.
In the example given in Figure E.11, over the latter part of the planned period, the SYS Planned Transfer lies within the 50% range of the probabilistic transfers. At the same time, the SYS capability falls to the lower end of the probabilistic range which indicates a high probability of further reinforcements being required.
This presentation, which is reported in detail in the chapter on Transmission System Capability in the main text, is useful for demonstrating the inadvisability of committing transmission reinforcements too far ahead of need and also for illustrating future opportunities. Please note that, whilst the 'SYS capabilities' displayed on Figure E.10 and Figure E.11 are appropriate for the 'SYS background' and 'SYS transfers', they do not necessarily correspond to the backgrounds covered by the probabilistic transfer range. Each background captured within the probabilistic analyses will have a unique set of boundary transfers and boundary capabilities. Taking into account both the probabilistic transfer levels as well as the boundary flows for the 'SYS background', the following provides a summary of the key indications for the future development of our transmission system:
In view of the uncertainty associated with the 'SYS background', the timing of the construction of infrastructure reinforcements is managed such that investments are made to well defined system requirements. This means that, generally, construction is deferred as far as is practicable to avoid undertaking investments that may turn out to be unnecessary, e.g. where transmission contracted generation does not in the event proceed. At the same time, in recognition of the individual TOs' obligations relating to the facilitation of competition, flexibility is planned into the GB transmission system such that it does not unduly inhibit the development of future projects. However, we do ensure that we can provide an efficient, co-ordinated and economic system, compliant with the security standards, as required by the Electricity Act 1989 and the Transmission Licences.
A number of significant connection and infrastructure reinforcements to the GB transmission system are currently planned. In addition to the construction of new overhead lines and substations, these include the use of devices that not only maximise the use of the existing transmission system thereby limiting environmental impact, but also enable rapid network modifications to meet changing system requirements. To this end we use, amongst other things, quadrature boosters, which are capable of being relocated at a later date together with Relocatable Static Var Compensators (RSVCs). We have also authorised the reprofiling (i.e. retensioning of the overhead line circuits to reduce the sag between towers) of strategic overhead line circuits to increase the permitted operating temperature and thereby increase their load carrying capability.
By exploiting the capability of the existing transmission system through the installation of quadrature boosters and reactive compensation and overhead line conductor re-profiling, we will continue to maximise the use of our existing lines.
In the generation context, opportunities are interpreted as the ability to connect new generation without an associated need for major transmission reinforcement, which could in turn lead to delays caused by the need for Planning Consent and possible Public Inquiries.
Figure E.12 separates the 17 SYS Study Zones into five opportunity groups, namely: VERY LOW, LOW, MEDIUM, HIGH and VERY HIGH. The figure also provides an indication of the capacity of new generation that can be accepted in the individual zones of each opportunity group without the need for major transmission reinforcement.
It does not follow that all the generation capacity within an opportunity group could be located at one site within a zone. In some zones, for example the London Zones, a considerable spread would be necessary. Nor does it follow that the capacities indicated for each zone within an opportunity group could be accepted together. Moreover, please note that there is little opportunity for further connections in the northern zones.
Whilst levels of opportunity have been attributed to the five opportunity groups, it does not follow that the full opportunity capacity indicated could be used up without further detailed consideration. For instance, whilst the South West England (zone 17) falls into the 'Very High' opportunity category, any development totalling in excess of, say, 2GW would require local reinforcement, which could possibly reach outside the immediate zone without major transmission reinforcement.
The above guidance is necessarily general and emphasises the need to consider individual prospective generation developments on their merits at the time of application. A message arising from the guidance is that new generation located in the South is far less likely to incur the need for major inter zonal transmission reinforcement and possible time delays than generation located in the North.
The analyses of boundary power transfers show that, with the material increase in new generation (18.2GW) planned for the next seven years, the resultant power flows through the Scottish and English grid systems to the Midlands would require significant reinforcement. In view of this, it is unlikely that any new applications for generation projects in Scotland or the north of England can be accommodated within the seven year period covered by this Statement.
Notwithstanding the above opportunity messages, we will continue to comply with our licence obligations to make offers and will endeavour to meet our customers requirements including those relating to timescales.
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New demand of up to 150MW could be connected within most zones without requiring major transmission reinforcement. However, a large localised demand increase within the London system could well precipitate the need for major work depending on the precise location.
Additional demand of this size in the South could, under certain circumstances, advance the need for major inter-zonal transmission reinforcement between the north and south of the system. Each case again needs to be considered on its own merits.
The 2006 Great Britain Seven Year Statement (GB SYS) is the second to be published by National Grid Electricity Transmission plc (NGET), acting in its role as Great Britain System Operator (GBSO). National Grid Electricity Transmission plc is a member of the National Grid plc ("National Grid") group of companies.
The Statement is produced in accordance with the obligations placed on National Grid, as GBSO, under the System Operator Standard License Condition C11 of National Grid's Transmission Licence. Amongst other things, that condition requires that National Grid publish a GB SYS on an annual basis and in a form approved by the Authority. The two Scottish transmission licensees are required to assist National Grid in preparing this GB SYS pursuant to their licence obligations. A key purpose of the GB SYS is to assist existing and prospective new Users of the GB transmission system, whether generators or suppliers of electricity, in assessing the opportunities available to them for making new or additional use of the GB transmission system in the competitive electricity market in Great Britain.
The implementation of the New Electricity Trading Arrangements (NETA) in March 2001 represented a fundamental change in the basis of electricity trading in England and Wales. With the implementation of BETTA on 1 April 2005, these trading arrangements were extended to incl ude Scotland and consequently now cover the whole of Great Britain. The commercial impacts have been and will continue to be far reaching. However, the fundamental physics of the power system, including the GB transmission system, remain essentially unchanged.
Accordingly, whilst the text in this Statement reflects new terminology, institutional, contractual and other changes relating to BETTA, the subject matter presented remains much the same as that of each of the previous, pre BETTA, Statements produced by the three Transmission Licensees in Great Britain, namely: National Grid plc ("National Grid"), SP Transmission Ltd (SPT); and Scottish Hydro-Electric Transmission Ltd (SHETL). The two Scottish Transmission Licensees have assisted National Grid in preparing this GB SYS.
For those readers who are unfamiliar with the new arrangements, Market Overview provides a high level summary of BETTA and reports on a number of related issues such as governance, institutional and contractual arrangements.
The chapter entitled Embedded and Renewable Generation has been included in recognition of the current and potential future growth in embedded and renewable generation given the government's targets for generation from combined heat and power (CHP) and renewable sources.
The Statement presents a wide range of technical and non-technical information relating to the GB transmission system in a series of chapters and appendices. The subject matter includes: projected demand; generation; embedded generation (as mentioned above); plant margins; the characteristics of the existing and planned GB transmission system; its expected performance (including power flows; loading, fault levels and its capability to transfer electricity across the system); opportunities and the electricity market (also mentioned above). As far as possible each chapter is self contained with appropriate text, tables and figures.
The nomenclature of the table heading reflects the chapter to which it belongs (e.g. Table 3.4 is the fourth table in the chapter entitled Generation . In some cases where a table contains a large amount of material of a general nature or where the figures are particularly large, then those tables and figures have been included in an appendix and referenced with a prefix associated with the relevant appendix e.g. Figure A.1.1 is included in Additional Figures and Table B.1a is included in Data.
Additional Figures , Data , Power Flows and Fault Levels present technical information relating to the GB transmission system and its performance in diagrammatic and tabular form. This material is introduced and referenced in the main text.
Much of the data included in this GB SYS is provided by Users and potential new Users of the GB transmission system other than National Grid and the two Scottish Transmission Licensees. There are certain obligations placed on ourselves (e.g. Clause 6.15 of the Connection and Use of System Code) regarding the use of such data with respect to 'disclosure of commercial interests'.
In view of this, the customer demand and generation information listed in the Statement and used to produce the forecast power flows is generally restricted to that for which an appropriate Bilateral Agreement has been entered into between the relevant Transmission Licensee and the customer. Speculative new projects, potential closure of existing stations or other developments that may have been discussed with the relevant customer are not included without the agreement of the customer. In this Statement, present and future customer developments for which appropriate Bilateral Agreements have been entered into are generally referred to as 'transmission contracted'.
Similarly, unless otherwise stated, the transmission network presented includes developments needed for the 'transmission contracted' demand and generation projects and excludes transmission works that may be needed to accommodate prospective (i.e. not as yet the subject of an appropriate Bilateral Agreement) new or modified projects for demand or generation.
It should be noted that some proposed transmission developments included in the background may also be subject to planning consent as may the transmission contracted demand and generation projects.
Unless otherwise stated, the network analyses (e.g. the illustrative power flows, the loading on each part of the GB transmission system and the fault levels) presented in the GB SYS is based on a system background referred to as the "GB SYS Background", which is often shortened to "SYS background". The SYS Background is made up of the following:
(i) Demand Background: The "customer-based" demand forecasts rather than the "NGET based" GB demand forecasts. Both sets of demand forecasts are reported in Electricity Demand;
(ii) Generation Background: Unless otherwise stated the existing generation and that proposed new generation for which an appropriate Bilateral Agreement (i.e. BCA, BEGA or BELLA) is in place. This would include projects within GB Offer "Group A" and some projects in GB Offer "Group B". This is detailed in Generation Capacity; and
(iii) Network Background: The existing transmission network and those future transmission developments, which are considered "firm" in that they are least likely to be varied or cancelled as the needs of the evolving system change. Such transmission developments will include, but will not be restricted to, those schemes, which have been technically and financially sanctioned by the relevant Transmission Owner. A number of additional schemes, which are also considered "firm", may also be included. These additional schemes are in respect of transmission reinforcements associated with generation projects included in the generation background of (ii) above. Transmission network information is detailed in GB transmission system.
Please note that the terminology used in the above background descriptions is explained in the Glossary.
The "SYS background" is internally consistent. For example, the transmission background of item (iii) above includes all transmission connection developments cited in the relevant connection agreement as being necessary to connect the generation contained in the background of item (ii) above. The "SYS background" does not include any transmission development that may be needed to accommodate prospective projects of new generation or demand, which do not have an appropriate Bilateral Agreement in place on the Data Freeze Date of 1 December 2005, and which are therefore not reported under item (ii) above. The connection dates used reflect the contracted position.
It is recognised that the above 'SYS background' does not necessarily represent the most likely outturn. For example, it is reasonable to suppose that new applications for power station connections will be received, some power stations will close and some contracts for generation projects may be modified or terminated. This may lead to the need to vary the planned future development of the transmission system to meet changing system requirements. Whilst the main body of this Statement is based on the 'SYS background', future uncertainties and their effect on system performance, the need for transmission reinforcement and resultant opportunities have also been considered in the relevant chapters.
In view of the uncertainty associated with the need for future developments, the timing of construction of reinforcements to the Main Interconnected Transmission System (MITS) is managed such that investments are made to well defined requirements. Accordingly, in some cases, reinforcement of the MITS may be deferred to the last moment to avoid the risk of undertaking investments which may, in the event, turn out to be unnecessary. In view of this, the "SYS background" may not necessarily contain all the MITS reinforcement schemes required for compliance with the Licence Standard. However, this Statement does include an indicative list of reinforcement schemes, which would maintain compliance with the Licence Standard.
The information provided in this Statement will, amongst other things, enable existing customers and potential new customers to identify general opportunities for new, continued and further use of the GB transmission system. When a customer is considering a development at a specific site, certain additional technical information in relation to that site may be required which is of a level of detail that is inappropriate to include in a document of this nature.
In such circumstances the customer may contact the appropriate Transmission Licensee, initially the relevant technical contact (address in Contact Us), who will be pleased to arrange a confidential discussion, and the provision of such additional information relevant to the site under consideration as the customer may reasonably require.
Customers wishing to make an Application for an appropriate Bilateral Agreement to the Connection and Use of System Code (CUSC) and wishing to discuss the possible terms of such an agreement or obtain an application pack, should initially contact the relevant commercial contact (address in Contact Us).
Other useful addresses together with a list of documents produced by ourselves and others which readers may find helpful, can be found in Contact Us and References.
The main Statement is supplemented by a set of Updates. The first Update will be issued shortly after publication of this main Statement and will report on changes notified since the data freeze date. As in previous years, further Updates will be issued on a regular basis (approximately three month intervals). Quarterly Updates provide a brief summary of the key changes since the main Statement was produced. No new simulations are carried out for the Updates but an estimate is made of the effect of the changes on the various issues covered by the Statement.
The 'Data Freeze Date' for all information included in this Statement reflects, unless otherwise stated, the extant position on 1 December 2005. Subsequent developments are reported in the Quarterly Updates.
This chapter presents forecasts of electricity demand to be met from the GB transmission system. The main forecasts are based on information submitted by Customers who take (or propose to take) electricity from the system. These 'User' based forecasts, together with the generation and transmission backgrounds described in the chapters on Generation and GB Transmission System respectively, form the basis of the SYS background upon which most of the studies and analyses presented in this Statement are based.
NGET's own 'base' forecast of electricity demand to be met via the GB transmission system is also presented, along with alternative 'high' and 'low' scenario forecasts. Unlike the 'User' based forecasts, which include details of individual Grid Supply Point demands, the NGET forecasts are global projections for Great Britain. These forecasts are included as supplementary information and reflect our views on possible outcomes based on specific assumptions, which are reported and discussed.
In general, the level and location of generation remains the major factor in determining the need for transmission reinforcement. However, in some areas (e.g. importing areas) demand can exert the greater influence and as such there is an increasing need for accurate demand forecasts in terms of both level and location.
Additional explanatory information is also given, including an explanation of the sources of the customer demand data, how it is processed and the terminology used.
Peak unrestricted demand on the GB transmission system in ACS (average cold spell) conditions, as projected by the system 'Users', increases from 62.8 GW in 2006/07 to 68.6 GW by 2012/13. This represents a growth rate of 1.3% per annum (see Table 2.1). An explanation of the ACS correction procedure is given in the Supplementary Demand Information section of this chapter. The forecasts are in respect of the time of the simultaneous peak demand on the GB transmission system and accordingly take account of any diversity between the individual peak demands on each of the systems of the three Transmission Licensees (i.e. NGET, SPT and SHETL).
Peak demands represent the demand on the GB transmission system to be met by Large Power Stations (directly connected or embedded), Medium and Small Power Stations which are directly connected to the GB Transmission System and by electricity imported directly into the GB transmission system from External Systems. They are therefore net of any allowance the User chooses to make in his demand forecasts for the output of Medium Power Stations, Small Power Stations or Customer Generation embedded within distribution networks, and imports across embedded External Interconnections to these systems (i.e. Isle of Man). Distribution and transmission system losses (see Table 7.4) are included, as are exports across External Interconnections to External Systems.
Last year's 2005 GB Seven Year Statement was the first Seven Year Statement to encompass the complete GB transmission system. In addition to extending the demand forecasts to include England, Wales and Scotland, the ACS correction methodology was also updated. An explanation of the new ACS correction procedure is given in the Supplementary Demand Information section of this chapter.
One particular change to the ACS methodology was made in order to address the significant fall-off experienced in the amounts of demand response/management by customers being notified under the Grid Code. The latter made it increasingly difficult to derive realistic historical 'unrestricted' demands, i.e. actual metered ('restricted') demands plus notified demand response/management by customers, on which to base the ACS correction. As a result, ACS demands are now calculated from historical 'restricted' rather than 'unrestricted' demands. (For the avoidance of doubt, 'restricted' demand is the level of demand after taking into account any demand response/management by customers, ie it represents the actual metered outturn, whereas 'unrestricted' demand takes no account of the impact of any demand response/management by customers).
Because of this change, ACS outturn and forecast demands presented in last year's Statement were given on a 'restricted' basis. However, infrastructure planning for the transmission system continues to be based on ACS 'unrestricted' demands. This prudent approach in transmission planning is made on the basis that demand response/management by customers cannot be fully relied upon to be enacted at peak times. Accordingly, ACS 'unrestricted' demand outturns and forecasts are still required.
Following the ACS methodology change, 'unrestricted' ACS peak demands are now derived by analysing demands around the time of weekday evening peaks during the winter to obtain estimates of the total amount of customer demand response/management by customers (both notified and un-notified) in force at peak times. (The resulting amounts, approximately 1GW, are similar to the levels of load management being notified during the 1990s). Adding the load management estimates onto the historical 'restricted' ACS outturns yields 'unrestricted' outturns which form the basis of the ACS outturns and forecasts given in this Statement.
As a cautionary note, other related documents may refer to 'restricted' rather than 'unrestricted' demands, a case in point being National Grid's 'Winter Outlook Report'. Naturally, therefore, care should be exercised when making comparisons between demand forecasts on different bases.
On a point of detail, the demand of power stations supplied directly (via the station transformers) from the GB transmission system are included in the ACS demands presented in this chapter (but no pumping at pumped storage stations is assumed to occur at peak times). However, for ease of reference and convenience, Table 2.1 presents the 'User' demand forecast stream both including and excluding power station demand. This recognises that the term Transmission Entry Capacity (TEC), which is a key term used to describe power station output, is used extensively in other analyses presented elsewhere in this Statement (e.g. power system analyses and Plant Margin evaluation). By definition, TEC is net of station demand and accordingly ACS Peak GB Demand excluding station demand is used where relevant to avoid it being double counted.
Figure 2.1 shows recent outturns and the current 'User' forecasts of ACS peak demand on the GB transmission system.
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It is explained under the Customer Demand Data section that, while the local peak demand is used for Grid Supply Point planning, the demand at the time of the GB system peak is used for infrastructure planning purposes. That section also explains that transmission losses are added to the Users' demand submissions, after which they are adjusted such that the aggregate of 'User' demand projections for the base year (2005/06) is scaled to the provisional or, if known, final ACS corrected outturn. The resulting adjustment factor is applied to subsequent years, thus retaining customers' aggregate forecast annual growth rates. (These forecasts are amended when necessary in SYS Quarterly Updates to align with final base year ACS outturns).
Grid Supply Points (GSPs) are the points of connection between the GB transmission system and the distribution networks and/or Large Power Stations. The times of individual GSP peak demands can vary from GSP to GSP and as such may not coincide with the time (or date) of the GB system peak. The series of tables, Table 2.2a , Table 2.2b , Table 2.2c , Table 2.2d , Table 2.2e , Table 2.2f , and Table 2.2g , list the 'User' based forecasts of maximum demand for each GSP firstly in respect of the time of the GSP peak and secondly in respect of the projected time of the GB system peak. These demands are measured at the GSP and accordingly include distribution losses but, unlike the demands given in Table 2.1, they do not include transmission losses.
The final column in Table 2.2a of the above series gives DCLF Node information. This has been included to enable a User to identify the HV Direct Current Load Flow (DCLF) transport model node at which LV demand is mapped for the purpose of calculating Transmission Network Use of System (TNUoS) tariffs (please refer to Use of System Tariff Zones) and producing the Condition 5 information paper which forecasts the future path of the locational element of the TNUoS tariffs. The additional column is included for information purposes, but it should be noted that the GB Peak figures included in the table will not necessarily exactly match those demand figures contained in the DCLF transport model as adjustments to the data are made to allow for station demand and generation is treated as negative demand.
The series of tables, Table 2.3a , Table 2.3b , Table 2.3c , Table 2.3d , Table 2.3e , Table 2.3f , and Table 2.3g, provide GSP information at the projected time of the minimum GB system demand.
For grid supply point planning, demand at each GSP's peak is used, together with appropriate allowances for embedded Large Power Stations, in accordance with the Licence Standard. An allowance for generation by Medium and Small Power Stations and imports across embedded External Interconnections is already made in the customers' demand projections. For completeness, Tables 2.2 and 2.3 also list Large Power Stations connected to GSPs or embedded in the distribution networks behind GSPs, together with demand power factors.
Figure 2.1 shows recent actual and ACS Peak GB Demands along with the latest 'User' based projections of ACS peak demand on the GB transmission system. Correcting historical demands to ACS conditions enables underlying demand patterns and trends to be more readily observed.
Many factors can influence the level of peak demand met by the transmission system. These include the weather, economic activity, energy conservation, competition from other fuels, the take up of self-generation, supplies taken from generation embedded within distribution networks, the extent of customer demand response/management by customers and the level of interconnector exports.
For many of the above factors, the effects are relatively small over time so they may have little impact on year to year changes in transmission system demand. However, factors such as the level of economic activity and, more particularly, the weather, can cause wide variations in demand from one year to the next, especially for peak demand.
Actual GB peak demand in the winter of 2005/06 (at 60.3GW) was 800MW higher than in the previous winter. The ACS correction procedure, which is outlined in Supplementary Demand Information, eliminates the weather effects and gives a better indication of the underlying pattern of annual peak demand (see Table 2.4 and Figure 2.1). Correcting winter weekday demands to ACS conditions yields a provisional 'unrestricted' peak of 62.8GW in 2005/06, reflecting zero growth on the 2004/05 ACS outturn.
The definition of demand used throughout this Statement is explained and discussed in the section on Demand Terminology and includes exports to External Systems. Before the commencement of the New Electricity Trading Arrangements (NETA) in March 2001, little power was exported across the External Interconnector with France. However, under NETA and its successor the British Electricity Trading and Transmission Arrangements (BETTA), the cross-channel link has been operating more on a two-way basis, although exports to France do not tend to occur at GB system peak times and imports have still predominated at other times. In addition, since it became operational in 2002, the 500MW link between Scotland and Northern Ireland has been solely used to export power to the province.
Figure 2.2 presents daily demand profiles for the days of maximum and minimum demand on the GB transmission system in 2005/06 and for days of typical winter and summer weekday demand. (Note that these demands are shown exclusive of station transformer, pumping demand and interconnector exports).
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Whilst Figure 2.2 shows how demand varies through the day in summer and winter, Figure 2.3 plots weekly maximum and minimum demands in 2005/06 to indicate how demand varies over the year. As with Figure 2.2, these demands are exclusive of station and pumping demand and interconnector exports.
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Figure 2.4 shows the GB annual load duration curve for 2005/06. Based on demand data for every half hour of the year, it shows the percentage of time in the year against the proportion of the year's peak. For example, demand exceeded 50% of the annual peak for more than 85% of the time.
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The 'User' based peak demand forecasts presented in this Statement are based on the aggregation of 'User' submissions (see Table 2.1). These 'User' based forecasts form part of the SYS background upon which most of the studies and analyses presented in this Statement are based. However, for comparison, NGET has provided it's own 'base', 'high' and 'low' demand scenarios.
For the 'high' and 'low' demand scenarios, combinations of favourable and adverse developments are assumed which yield high and low transmission system demands. For example, in the low scenario good progress towards the government's 2010 targets for combined heat and power and renewables is assumed, resulting in strong growth in embedded generation. In contrast, in the high demand scenario circumstances bring a much slower take-up of such schemes and hence embedded generation. These assumptions, along with variations for other factors such as economic growth and energy efficiency, result in a fairly wide range of outcomes for transmission system demand.
When compared with NGET's 'base' projections, the 'User' based forecasts show stronger growth (illustrated in Figure 2.5). In submitting their forecasts, 'Users' are not required to provide information on their background assumptions. Possible reasons for the transmission system demand differences include alternative views on factors such as economic prospects and the growth of demand met by embedded generation.
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Details of NGET's peak demand and electricity requirements projections and the main economic assumptions underlying them are given in Table 2.5 and Table 2.6. (Please note that the economic forecasts on which they are based have been provided by Experian Business Strategies).
The UK economy has suffered a loss of momentum since mid-2004 with below-trend GDP growth recorded in each quarter since then. For 2005 as a whole, the economy expanded by 1.8%, significantly down from the 3.2% growth seen in 2004. However, 2006 is expected be a turning point with consumer spending making a modest recovery and business investment and exports seeing healthy growth. Over the period of this forecast, although GDP expands more slowly relative to the last cyclical period, average growth of around 2.7% per annum remains above most estimates of the UK's long-run trend growth.
Despite the economy's expected improvement, growth patterns across sectors remain uneven. In 2005/06, manufacturing lost the momentum it had built up through 2004/05, despite the benefits of strong global growth. Output in the service sector also slowed, mainly as a result of the more subdued consumer spending activity and weaker tourism.
For manufacturing a steady improvement rather than a sharp upswing is forecast. The global backdrop remains favourable, despite dollar weakness and enduring uncertainty over oil prices. Following the sector's stagnation in 2005/06, expansion of around 2% is projected for manufacturing in both 2006/07 and 2007/08, before growth settles back thereafter to average 1.8% per annum overall.
Service sector activity looks to have peaked at 4% during 2004/05, with growth in public services being bolstered by the expansionary fiscal climate of recent times. Spending has moderated as a result of the government tightening fiscal policy, leaving private services to drive expansion. Transport & Communications, particularly Telecommunications, is expected to rebound strongly in response to strong domestic and international activity. The service sector overall is expected to see growth averaging almost 3½% per annum.
Having outstripped GDP growth for much of the period since the mid-1990's, weaker confidence and a cooler housing market mean that consumer spending growth averaging 2.3% per annum will lag behind GDP growth over the forecast period.
Oil and gas prices have risen sharply over the last couple of years and the predominance of gas as the fuel for electricity generation has resulted in significant end-user electricity price increases. Further rises are projected for this year an next, with prices thereafter falling back in real terms.
Against the background outlined above, total GB annual electricity demand is projected to increase by 1.1% per annum over the period 2005/06 to 2012/13. This growth relates to both power supplied from the transmission system and that met from generation embedded within distribution systems. However, growth of the latter is expected to constrain growth seen on the transmission system.
After it took office in 1997, the government endorsed its predecessor's target of 5GW of installed electrical combined heat & power (CHP) capacity in the United Kingdom by 2000 (a target which was actually reached during 2004). A further objective of at least 10GW of electrical CHP capacity by 2010 was subsequently proposed as part the government's strategy for achieving environmental emissions targets under the Climate Change programme.
However, recent years have seen the price of gas, the predominant fuel for CHP, increasing faster than electricity prices. This has resulted in many potential developers either abandoning or postponing planned CHP schemes. Over the period of this forecast a very modest recovery from the near moratorium of recent years is assumed for CHP, with electrical capacity reaching 6.5GW in 2010/11.
In addition to CHP, the incoming government in 1997 endorsed its predecessor's target for renewable capacity, i.e. 1.5GW on a declared net capability (DNC) basis, excluding large-scale hydro, which had been set for the United Kingdom by the end of 2000. (A target which was achieved during 2003).
A new goal for renewables was added by way of the Renewables Obligation (RO) which requires increasing proportions of electricity sold by licensed suppliers to be sourced from qualifying renewable fuels. In 2004 electricity from such fuels accounted for 3.1% of electricity sales, up from 2.2% in the previous year, but below the 4.9% level set for 2004/05.
The NGET 'base' forecast assumes that the obligation on suppliers to source increasing amounts of electricity from renewable sources will see continued growth in such generation, particularly wind and the resulting forecast indicates a 7.4% share by 2010.
Of the new CHP and renewable generating capacity, that which is embedded within distribution networks, if utilised, reduces the growth in demand seen on the transmission system. In the 'base' forecast this demand is projected to rise by 0.6% per annum, compared with 1.1% per annum projected for overall electricity use.
Since it became operational, the 500MW External Interconnector between Scotland and Northern Ireland has been used solely to export power to the province. The 'base' forecast assumes exports of 300MW across it at peak times, with 1TWh projected annually.
With regard to the External Interconnector between England and France, no exports are projected to occur at GB system peak times. In 2003/04, annual exports to France of almost 3TWh were seen, but in other years since NETA was introduced exports of 1TWh or less have been recorded Over the duration of this forecast, the interconnector is assumed to continue to be primarily utilised to import power from France, with up to 1TWh per annum projected for exports.
In summary, the 'base' forecast shows annual electricity requirements on the GB Transmission System rising from 355TWh in 2005/06 to 370TWh in 2012/13, i.e. average growth of 0.6% pa. ACS 'unrestricted' peak demand also increases by 0.6% pa, from 62.8GW in 2005/06 to 65.4GW in 2012/13.
This upside economic scenario is based on more optimistic assumptions about supply side economic performance over the medium term. This is chiefly seen in stronger productivity improvements, which translate into higher GDP growth. Manufacturing benefits most from the productivity gains, with the sector's output expanding by 2.3% per annum. The service sector, at 3.8% per annum, retains its place as the fastest growing sector, whilst consumer spending growth at 2.6% per annum lags a little behind overall GDP growth of 3.1% per annum.
The higher economic growth underpinning this scenario results in strong growth in the use of energy, with overall annual electricity demand increasing by 2.1% per annum. With slow rates of take-up assumed for both CHP and renewable generation embedded within distribution networks, annual requirements met via the GB transmission system, grows at a similar rate, rising from 355TWh in 2005/06 to 413TWh in 2012/13. ACS peak demand increases from 62.8GW to 73.4GW over the same period, growth of 2.3% per annum.
In this downside scenario economic growth is slower due to weaker employment, more subdued productivity growth and a more pessimistic outlook for consumer demand. Overall, GDP growth averages 2.4% per annum with a slightly slower increase for consumer spending (2.1% per annum). As with the 'base' and 'high' scenarios, there are contrasting fortunes for the service sector (3.0% per annum) and manufacturing sector (1.4% per annum).
A particularly high profile is assumed for environmental issues in this scenario, with energy conservation encouraged by way of investment and subsidies on both the demand and generation sides. Energy efficiency schemes for domestic and business customers are heavily promoted and investment in more efficient generation sees good progress towards the environmental targets set for 2010 for CHP and renewable energy.
Against the background outlined, overall annual demand for electricity rises by 0.1% per annum. However, the effects of significant embedded CHP and renewables growth result in a reduction in demand seen on the GB transmission system with annual requirements declining by 1.2% per annum from 355TWh in 2005/06 to 325TWh in 2012/13. Peak demand met via the GB Transmission System falls by 1.4% per annum, from 62.8GW to 56.9GW over the same period.
Customers who load manage in response to high electricity prices and/or triad demand charges can either reduce their production or, if available, fall back on their own generation in order to maintain output. In these circumstances the form of self-generation used would normally be of a standby nature since other main forms of own generation such as combined heat and power (CHP) would be likely to be already in operation.
In 1993, as part of a programme to reduce carbon dioxide emissions, the government set a target of increasing the electrical capacity of combined heat and power in the United Kingdom from 3GW to 5GW by the year 2000. More recently the current government, as part of its Climate Change strategy to reduce CO2 emissions in 2010 by 20% of their 1990 level, has proposed a further target of 10GW of electrical CHP capacity by 2010 (see Embedded and Renewable Generation).
Increases in the capacity, and hence use, of CHP and other forms of self-generation, particularly that which is not of a standby type, would be expected to result in commensurate falls in the level of demand met from the transmission system, although this does not necessarily mean a reduction in the system's use. For example, the location of new self-generation in some areas could result in increased system power flows as a consequence of the displacement of local demand previously met by local generation, leading to the surplus local generation being transported elsewhere by the GB transmission system.
Every 'User' who takes, or expects to take, demand directly from the transmission system via a Grid Supply Point (GSP) is required by the GB Grid Code to provide NGET with demand forecasts with respect to that GSP. These forecasts are required to be submitted by Week 24 (i.e. mid-June) of each year, although revisions can be provided after this date.
'Users' who take demand directly from the transmission system are, in the main, the distribution network operators. In addition some industrial sites are directly connected to the transmission system and most Large Power Stations' own demand is also met from it via their station transformers. The Week 24 forecasts are used for, amongst other things, studying power flows on the transmission system. Accordingly the Week 24 submissions, which are given in respect of each of the seven succeeding financial years, include:
(i) the demand the network operator expects to take from each GSP at the time of the expected system demand peak (the date and time being advised in advance by NGET) - primarily for use in infrastructure planning; and
(ii) the maximum demand the network operator expects to take from each GSP at any time - primarily for use in GSP planning.
In both cases (i) and (ii) above, network operators are required to make their own allowance for demand met by Medium and Small Power Stations embedded within their networks and for imports across embedded External Interconnections.
When planning the development of the transmission system, account is taken of all Large Power Stations, whether embedded in a distribution network or directly connected to the transmission system.
For power flow studies and other system analyses, the total transmission system demand is derived from the Week 24 submissions as follows. Peak demand forecasts at the time of system peak provided by each customer are aggregated and projected transmission losses are added. A correction factor is then applied to the resultant total demand stream which scales the total for the initial year to the provisional (or final, if known) ACS corrected peak demand outturn. Subsequent years are then scaled by the same factor, thus retaining customers' projected annual growth rates. This scaling process was originally formulated with the approval of distribution network operators.
For Grid Supply Point (GSP) planning, the demand at each individual GSP's peak is used, together with appropriate allowances for embedded Large Power Stations, in accordance with the Licence Standard. For planning the development of the infrastructure of the main interconnected transmission system, as opposed to specific GSPs, the forecast unrestricted ACS Peak GB Demand is used. Use of the unrestricted demand for infrastructure planning recognises that demand response/management by customers cannot be relied upon in the planning time phase. Nevertheless, in the event of a sufficiently high level of certainty being attached to the implementation of demand response/management by customers we would take demand management into account within our infrastructure planning.
Actual outturn peak demands can vary considerably from one year to another depending on the weather, as well as other factors such as economic activity and consumer behaviour. ACS demand correction enables more meaningful comparisons to be made between outturn demands and allows forecasts to be made on a weather base that also conforms to security standard planning requirements.
National peak demand forecasts given in this Statement are based on average cold spell (ACS) weather conditions. These are the combination of weather elements (i.e. temperature, illumination and wind) that give rise to a level of peak demand within a financial year that has a 50% chance of being exceeded as a result of weather variations alone.
Previously, ACS outturn peak demands (and hence forecasts) were based on 'unrestricted' demands derived by adding the load management enacted at peak notified by 'Users' under the Grid Code to winter weekday outturn peak demands. The 2005 GB SYS, was the first Statement to cover the whole of the GB transmission system and in addition to extending the demand forecasts to include both England, Wales and Scotland, the ACS correction methodology was updated.
One particular change to the methodology was made in order to address the significant fall-off experienced in the amounts of demand response/management by customers being notified under the Grid Code. The latter made it increasingly difficult to derive realistic historical 'unrestricted' demands, i.e. actual metered ('restricted') demands plus notified demand response/management by customers, on which to base the ACS correction. As a result, ACS demands are now calculated from historical 'restricted' instead of 'unrestricted' demands. (For the avoidance of doubt, 'restricted' demand is the level of demand remaining after taking into account demand response/management by customers, i.e. it represents the actual metered outturn, whereas 'unrestricted' demand takes no account of the impact of any demand response/management by customers).
Although the ACS correction procedure now produces historical 'restricted' demands, infrastructure planning for the transmission system continues to be based on ACS 'unrestricted' demands. This prudent approach is made on the basis that load management cannot be fully relied upon to be enacted at peak times. Therefore, ACS 'unrestricted' demand outturns and forecasts are still required. These are obtained by adding estimates of load management obtained from analysis of demands around the time of weekday evening peaks to the calculated ACS 'restricted' peak demands. The resulting ACS 'unrestricted' demands provide the platform for producing 'unrestricted' demands forecasts.
As a cautionary note, other related documents may publish 'restricted' rather than 'unrestricted' demands, a case in point being National Grid's 'Winter Outlook Report'. Naturally, therefore, care should be exercised when making comparisons between demand forecasts on different bases.
The methodology for identifying ACS demand comprises two main parts. In the first part, a mathematical model that estimates demand/weather coefficients from historical 'metered' demands (i.e. actual outturn peak demands) is identified. The modelling uses the latest four winters' demands, rather than a longer historical period, to ensure that the most recent demand behaviour is captured as well as to include as much weather variation in the modelling data as possible. Weather and demand data over the GMT period (i.e. late-October to late-March) for weekday peak half hours is modelled to give:
Winter Weekday Darkness Peak Demand is equal to the sum of the following:
The weather dependent demand at the darkness peak is a function of the:
The effective temperature (TE) is an average of the current and previous day's temperature at the time of the winter darkness peak. Cooling power (CP) is an empirical combination of temperature and wind speed, similar to wind chill. Effective illumination (EI) is a function of solar radiation, taking in to account the number and type of cloud layers, visibility and the amount and type of precipitation, although at the time of the darkness peak in mid-winter this is zero.
In the second part of the methodology, the coefficients are used to carry out a simulation analysis of Winter Weekday Darkness Peak Demand (WWDPD) for the last winter. Simulations of the Weather Dependant Demand & Day of the week are fed into the WWDPD model for each Electricity Supply Industry (ESI) week (where weather dependent demand is described above and estimated from TE, EI & CP actuals which are aggregated from regional weather stations collected for the last thirty years).
The peak of the simulated Winter Weekday Darkness Peak Demands for each of 10,000 winter simulations are ordered and the median demand (50th percentile) is identified as the ACS demand (i.e. the level of peak demand that has a 50% chance of being exceeded as a result of weather variation).
Demand Definition
The definition of the term 'ACS Peak GB Demand' given in the Glossary of Terms has been written for the purpose of this Statement. The meaning of the term may differ in some respects in other documentation. Figure 2.6 provides a useful generalised illustration of the definition and also aids comparison with other demand terms in current usage.
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The figure shows the different categories of demand directly connected to the transmission system together with the demands supplied from the distribution networks, which are in turn directly connected to the GB transmission system at Grid Supply Points (GSPs). Transmission and distribution losses are also included.
In Figure 2.6 the area within the red border encapsulates those components of demand making up ACS Peak GB Demand. The generation which is used to meet ACS Peak GB Demand is bordered in blue. This generation comprises; directly connected power stations, whether Large, Medium or Small; embedded Large Power Stations; and imports from External Systems across directly connected Interconnections. Until the winter of 2001/02, exports to France across the Interconnection were exceptional. Since then, however, exports have become more common, although not at times of system peak. All these sources of generation is the subject of Generation.
In providing their demand forecasts for their Grid Supply Points the distribution network operators net off their own allowances for the output of embedded Medium and Small Power Stations, Customer Generation and also for the imports across embedded External Interconnections. Customer Generating Plant operates to supply all or part of its own electricity requirements and exports any surplus onto the local distribution network. Embedded generation is the subject of Embedded and Renewable Generation.
The SYS definition of ACS Peak GB Demand is in line with the GB Grid Code definition of "GB Transmission System Demand". Please note that in both cases (i.e. the above definition and the GB GC definition) the demand includes exports to external systems, Pumped Storage pumping demand and Station Transformer demand. This is unlike the GB GC definition of "GB National Demand", which specifically excludes those three demand categories.
It is assumed that there will be no exports to France at the time of the GB system peak, nor is there likely to be any significant demand at peak associated with pumped storage. However, where exports at peak are expected (e.g. from the SPT system to Northern Ireland), such exports form part of the "ACS Peak GB Demand". As a point of interest, the converse also applies, i.e. expected imports from External Systems at times of system peak contribute to supplying demand and are therefore treated as equivalent to generation. These assumptions reflect reasonable expectations of the position at the time of the GB system peak.
Netting Off Station Demand
The text of the preceding sections of this chapter focuses on the demand defined above as "ACS Peak GB Demand" and accordingly includes station demand (i.e. station auxiliary demand supplied through the station transformers). However, the Transmission Entry Capacity (TEC) of a power station is net of station demand. In view of this, care is required when conducting power system analyses or plant margin calculations lest double counting of station demand occurs. It is for this reason that the text of this chapter also identifies that component of "ACS Peak GB Demand" which is due to station demand to enable the reader to more readily identify the appropriate demand stream to be used in studies and analyses.
Imports From and Exports To External Systems
As previously mentioned, according to the definition of "ACS Peak GB Demand", Exports to External Systems form part of system demand and Imports from External Systems contribute to supplying system demand. According to the SYS definition of the "Plant Margin", this is the amount by which the total installed capacity of directly connected power stations and embedded Large Power Stations and imports from External Systems exceeds the ACS Peak Demand.
For the GB system the ACS Peak demand referred to is the "ACS Peak GB Demand", which correctly includes exports and no adjustments are required. However, given that TEC is used as the measure of the total installed generation capacity, the station demand is also removed from the forecast ACS peak demand stream (as discussed above) for the purpose of calculating plant margins.
Please note that the demand submitted by 'Users' in accordance with the Grid Code is net of the Users' allowance for the output of, not only embedded Medium and Small Power Stations, but also imports from External Systems across embedded External Interconnections.
Finally, Exports to External Systems do not form part of the Week 24 (or Week 28) data reported under the GB Grid Code. Accordingly, such exports are added in separately for the purpose of determining the "ACS Peak GB Demand". A case in point is the expected export to Northern Ireland from the SPT system at the time of the GB system peak. For the interconnector with France, zero exports at peak are assumed.
This chapter presents information on all sources of generation, which are used to meet the ACS Peak GB Demand as defined in the Glossary and presented in Electricity Demand. Accordingly, this chapter reports on all power stations directly connected to the GB transmission system, whether they are classified as Large, Medium or Small, all directly connected External Interconnections with External Systems and all Large power stations, which are embedded within a User System (e.g. distribution system).
Electricity Demand does not include demand which is supplied by embedded Medium and Small power stations or embedded External Interconnections with External Systems. Likewise, this chapter does not include information on these sources of generation. Such information is, however, included in Embedded and Renewable Generation.
Information provided in this chapter includes existing generation capacity, new generation capacity, generation disconnections, generation decommissionings, generation plant mix in terms of fuel type, geographic and system generation disposition
The chapter concludes with a short section on 'Generation Terminology'. Readers who are unfamiliar with current terminology are advised to first read that section before moving on to the main body of the chapter.
In recognition of the uncertainties associated with the future, unless otherwise stated the information presented in this chapter relates to existing generation projects and those proposed new generation projects, which are deemed most likely to proceed to completion. Accordingly, proposed future projects, which are classified as "transmission contracted" are included. These would include projects within GB Offer "Group A" and some projects within GB Offer "Group B". Both these terms are defined in the Glossary and discussed in Generation Terminology.
An exception to this general rule is Alcan's Lynemouth power station, which is embedded, Licence exempt and Large but currently has yet to sign a Bilateral Agreement. However, this power station does exist and is capable of spilling large amounts of power onto the system (circa. 400MW). In consequence, it is subject to special treatment in this GB SYS in that it is treated as "Transmission Contracted". Its capacity is not netted of the demand forecasts submitted by Users but, instead, is included as generation capacity used to meet the ACS Peak GB Demand.
The generation background presented in this chapter, together with the 'User' based demand background and the transmission background described in Electricity Demand and GB Transmission System respectively, form the basis of the SYS background upon which most of the studies and analyses presented in this Statement are based. These three elements of the SYS background (namely: demand; generation; and transmission) are internally consistent. For example, the transmission background of Chapter 6 includes all transmission connection developments cited explicitly in the relevant Bilateral Agreement as being necessary to permit the connection of the generation contained in the generation background presented in this chapter. It is worth repeating, however, that the SYS background does not include any transmission development that may be needed to accommodate prospective projects of new generation or demand, which did not have an appropriate Bilateral Agreement in place on the Data Freeze Date of 1 December 2005.
The requirements for generation projects to obtain the necessary consents (i.e. under Section 36 of the Electricity Act 1989 and Section 14 of the Energy Act 1976) is explained in Market Overview. Many of the tables giving information on generation introduced later in this chapter include an indication of whether that plant has obtained section 36 and/or section 14 (where appropriate) consents or not. This information is useful when considering the relative likelihood of a project proceeding to completion. For completeness, Table 3.2 and Table 3.3 have also been included. The information relating to England and Wales has been sourced from the Department of Trade and Industry. The information relating to Scotland has bee sourced from the Scottish Executive.
Table 3.2 lists power stations, not yet under construction, for which section 36 and/or section 14 consent has been given. Table 3.3 lists power stations, not yet under construction, for which section 36 and/or section 14 is currently under consideration. Figure A.1.5 shows the location of National Parks in England, Wales and Scotland. Consents may be easier to obtain outside these areas.
Transmission access is briefly discussed in Generation Terminology. The transmission access timescales are such that, at the time of writing, the dates by which some Users may be able to access the GB transmission system are subject to change. In recognition of this, certain assumptions have had to be made with regard to commissioning dates shown in this Statement.
In the case of generation projects in England and Wales, the commissioning dates used reflect the pre BETTA go-live contracted position. In the case of generation projects in Scotland, the commissioning dates reflect the relevant Users' requested connection date as advised to National Grid by the two Scottish TOs. As a consequence, the generation capacity values and, in particular, the dates from which the generation capacity values are shown (i.e. commissioning year) within this Statement should be regarded as indicative only as they are based on the position at the time of writing as submitted by the relevant Transmission Licensees.
Please also note that, in the great majority of cases the commissioning year given will correspond to both the 'contract' date and the assumed date of actual full commercial output from the plant in question. However, it may be that full commercial output may slip into the years following the contract date. In such cases, the assumed generation commissioning dates given would reflect the advice of the relevant generator.
In addition, rather than strict adherence to a formal transmission contracted position, a pragmatic assumptions relating to commissioning dates in the earlier years may be adopted to enhance the relevance of the information provided. Such an assumption would be made without prejudice and is intended to recognise the current consent status of the plant in question and the progress towards completion of the project.
Table 3.4 lists one such generation project affected by such an assumption and includes both the contract date and consents status.
Table 3.5 presents details of all power stations falling within the scope of this chapter including the output capacity of each over the seven year period, 2006/07 to 2012/13. Amongst other things, Generation Terminology explains that the relevance of the generation capacity terms Transmission Entry Capacity (TEC), Connection Entry Capacity (CEC) and 'Size of Power Station' is a function of the type of Bilateral Agreement in force. For a Bilateral Connection Agreement (BCA), both TEC and CEC are relevant. For a Bilateral Embedded Generation Agreement (BEGA) only TEC is relevant. For a Bilateral Embedded Licence Exemptable Large Power Station Agreement (BELLA), neither TEC nor CEC exists and the term 'Size of Power Station' becomes relevant.
In Table 3.5 the type of power station capacity (i.e. TEC or 'Size of Power Station') given for each of the seven years is denoted by an appropriate entry (i.e. 'yes') in the columns headed 'TEC' and 'Size of Power Station' towards the end of the table. Where CEC is relevant (i.e. for a BCA) a separate entry is included in the column headed 'CEC'. Please note that values of CEC are given in respect of year 2006/07 only.
The information is presented on the basis of Licensee then on power station type. For ease of reference the SYS Study Zone, in which each Power Station is located, is also given as is the Tariff Zone. The SYS Study Zones are explained under SYS Boundaries and SYS Study Zones and Tariff Zones are explained under Yse of System Tariff Zones.
Inspection of Table 3.5 reveals that the aggregate power station capacity (TEC and/or 'Size of Power Station') rises from 76.3GW in 2006/07 to 94.5GW by 2012/13. This is an increase of 23.8% or 18.2GW over the period from the 2006/07 winter peak to the 2012/13 winter peak. This net increase is made of the following:
The largest proportion of the overall increase is due to CCGT plant at 53.4% with CHP accounting for a further 3.3%. The second largest proportion of the increase is due to Wind with on-shore wind accounting for 27% and off-shore wind accounting for 18.2% of the increase. On this basis, the capacity of CCGT plant would overtake that of coal in 2008/09. By 2011/12, CCGT capacity would exceed coal capacity by 4.6GW and account for 35.6% of the total transmission contracted installed generation capacity. Similarly, wind generation capacity (both on-shore and off-shore) is set to rise to 9.4GW by 2012/13. These capacities do not include the embedded Medium and Small generation and embedded External Interconnections with External Systems. The capacity of such embedded generation sources is the subject of Embedded and Renewable Generation.
It should be remembered that the above figures reflect the current contracted position and take no account of future uncertainty. As mentioned previously, it is reasonable to suppose that further new applications for power station connections will be received and, at the same time, some existing contracts may be modified or terminated and some existing power stations will close.
The 'effective output' capacity of each Generating Unit is given in Table 3.6 along with a range of additional data relevant to the Generating Unit. The 'effective output' is simply the Registered Capacity of each Generating Unit scaled down, where both appropriate and necessary, such that the aggregate output of all Generating Units at a power station is limited to the value of the relevant Power Station TEC. This would not be 'appropriate' for a generating unit generating unit covered by a Bilateral Embedded Licence Exemptable Large power station Agreement (BELLA), since a BELLA power station does not have a TEC. Nor would it be 'necessary' should the aggregate unit Registered Capacity at a power station be equal to or less than the station TEC. For ease of reference, the SYS Study Zone is again included. Table 3.6 reflects the contracted position for the winter peak of 2012/13 as known at the data freeze date of 1 December 2005.
Three phase fault infeeds and reactive ranges are also given and these are at the interface between the Generating Unit and the GB transmission system i.e. on the higher voltage side of the generator transformer.
Table 3.7 lists the actual and projected changes in the installed generation capacity since the winter peak of 1999/00 up to the winter peak of 2012/13. Please note that the capacities up to and including the winter peak of 2002/03 are based on power station Registered Capacity (RC) while the capacities for 2003/04 onwards are based on either power station Transmission Entry Capacity (TEC) or power station 'Size of Power station', as appropriate (TEC being appropriate for BCA and BEGA power stations and 'Size of Power Station' being appropriate for BELLA power stations.
As well as new transmission contracted generation, the table also includes increases due to plant being returned to service from reserve (or closure), increases in import capabilities from External Systems, and some minor proposed changes in TEC. For consistency between the various tables presented in this Statement, all generation expected to commission before the winter peak of 2006/07 is classified as 'existing'.
The status of each development is shown in terms of whether the station is existing (by the winter peak of 2006/07), under construction and otherwise whether both S36 and S14 (where relevant) consents have been obtained.
A feature of the future commissioning stream shown in the penultimate line of Table 3.7 is the relatively high level of activity in relation to capacity increases (9.1GW) indicated for the year 2008/09. Some 2.2GW of this increase is attributable to new plant in Scotland (2.1GW of on-shore wind farms and 0.1GW of hydro) and some 6.9GW is attributable to new plant in England and Wales (4.2GW of CCGT plant, 0.6GW due to stage 1 of the Netherlands Interconnection and 2.1GW of off-shore wind). It is worth remembering, however, that, in the event, there may well be a more graded increase in activity over a number of years. The fact that a project is currently 'transmission contracted' is not an absolute guarantee that the project will proceed to completion since there are other factors, which may also influence that outcome (e.g. financing, fuel prices, consents etc.).
Table 3.8 complements Table 3.7 by providing an overview of the generation capacity additions over the period from 2000/01 to 2012/13. For instance, of the 27.3GW of additional transmission contracted capacity since 2000/01, 15.8GW or 58% is CCGT plant and 9.4GW or 34% is due to wind farms. Similarly, of the 8.8GW of new contracted capacity either existing or under construction, 7GW or 79% is CCGT plant and 1.2GW or 13.4% is due to wind farms.
Table 3.8 also separately identifies the capacity of future plant by type and according to whether the necessary consents have been obtained.
Table 3.9 lists generation projects, that became classed as transmission contracted since 1 December 2004. The table shows that, since that date, Bilateral Agreements have been entered into for 5.2GW of new generation capacity. This includes some 2GW of off-shore wind farms on the NGET system, 228MW of on-shore wind farms on the SHETL system and 800MW of on-shore wind farms on the SPT system. The remainder is made up of 2.1GW of CCGT capacity on the NGET system and 45MW of Biomass capacity on the SPT system.
Disconnection is normally the irreversible closure of a power station and requires formal notification to be given to us at least six months prior to the event. Table 3.10 lists notified generation disconnections (closures) since the year 2000 inclusive. In total there is 6.7GW. Please note that the capacities up to and including the winter peak of 2002/03 are based on power station Registered Capacity (RC) while the capacities for 2003/04 onwards are based on power station Transmission Entry Capacity (TEC). Please note that the actual date for the disconnection of both Dungeness A and Sizewell A is 31 December 2006.
Decommissioning also requires six months formal notification but is not irreversible. Generating Units with a notified Registered Capacity of zero are, for the purpose of this Statement, in the same category as decommissioned plant.
A Generator may wish to decommission or mothball a Generating Unit for a relatively long period for commercial reasons. In such an event the Generator may also wish to affect a corresponding reduction in the power station TEC in order to reduce the Use of System charges. At a later date, he may choose to 're-commission' the generating unit and return the Power Station TEC to its appropriate value.
As explained in PC.4.3.1 of the GB Grid Code, NGET use the TEC data (and CEC data for that matter) from the relevant Connection and Use of System Code (CUSC) Contract. The value of TEC is specified in Appendix C of the appropriate Bilateral Connection Agreement or Bilateral Embedded Generation Agreement. These are agreements entered into pursuant to paragraph 1.3.1 of the CUSC.
Paragraph 6.30 of the CUSC explains how revisions to the value of TEC may be made. TEC may be decreased provided that certain specified notice is given to National Grid. Generators are entitled to request an increase in TEC, up to a maximum of the relevant CEC, through the more protracted Modification Application process.
Where we have received notification from the Generator (in accordance with the CUSC requirements) that a particular generation source is to reduce its value of TEC, then the reduced value is accordingly attributed to that plant for the purpose of the power flow studies and analyses contained in this Statement. In the extreme, we may receive notification that a particular plant has reduced TEC to zero. This could, under certain circumstances, mean that additional transmission reinforcement work would be required before such plant is able to subsequently re-register TEC at a higher level and this may cause a delay. In view of this, the Generator may choose to maintain the value of Power Station TEC throughout in order to avoid any subsequent delays. Increases in station TEC above the extant contracted value are not possible without an appropriate Modification Application from the generator to us to modify the site specific Bilateral Agreement.
Where the Generator has notified us that the Output Usable is zero (e.g. unavailable due to maintenance), the full value of station TEC is still attributed to that plant for the purpose of power flow and fault level studies. This ensures that no transmission reinforcement, and possible delay, will be necessary when the plant is repaired and returned to service.
Table 3.11 lists Generating Units which have either been formally notified by the owner as decommissioned (effectively RC=0) or simply notified zero Registered Capacity covering the seven year period of this Statement. In either event they may effectively be classed as unavailable. The year shown is the year in which the decommissioning took place. The capacity shown is the capacity prior to decommissioning. Please note that decommissioning is commonly on a generating unit basis for which the terms Registered Capacity or Connection Entry Capacity apply. Transmission Entry Capacity relates to the power station and does not exist on a unit basis. However, the values of RC given in Table 3.11 may be taken as an equivalent reduction in power station TEC.
The negative entry included for Killingholme 1 (Units 1A, 1B, 1S, 2A, 2B, 2S) reflect the fact that those units are scheduled to be returned to service in 2006 having previously been 'decommissioned' over the period 2002 to 2004.
Table 3.11 shows that there is currently an overall reduction in potential power station capacity of some 3.4GW comprising: 534MW of OCGT plant; 2535MW of Oil plant; and 350MW of Coal plant. However it is unlikely that all this capacity could be returned to service. Of the 3.4GW, perhaps some 500MW to 1GW has the greatest potential to return to service. Even then, it should also be borne in mind that, were individual plants to be re-commissioned/returned to service, the full previous capacities may not necessarily be realised.
The GB transmission system currently has directly connected External Interconnections with the External Systems of France and Northern Ireland. The phased commissioning of an External Interconnection with the Netherlands system is planned over the period 2008/09 to 2010/11. The opportunities for making use of these External Interconnections are outlined in Opportunities. Table 3.12 sets out the notional import capabilities across the External Interconnections at the time of our ACS Peak Demand for use in our planning studies.
The cross-channel link with France is a DC link consisting of four pairs of cables connecting converter stations at Sellindge in Kent and Les Mandarins near Calais. The 1988 MW import level, which is applicable throughout the seven year period, is net of Interconnector losses.
The link between Scotland and Northern Ireland was commissioned in December 2001 with commercial operation commencing in January 2002. The interconnector is a DC link connecting converter stations at Auchencrosh in the 'South' zone of the SPT system and Islandmagee in Northern Ireland. The 500MW Auchencrosh converter station is supplied by a 275kV overhead line from Coylton substation and this is shown in Table 3.12. Although this interconnector can operate with power flows in either direction, the power flow has been predominantly from Scotland to Northern Ireland. An export (i.e. a demand) of 300MW has been assumed for the winter peak of each year. Accordingly, for the purposes of this Statement, the transfer to Northern Ireland is treated as demand on the GB transmission system and is included within the demand forecasts of Chapter 2 rather than as negative generation.
A DC link for interconnection with the Netherlands electricity system is planned in stages for the years 2008, 2009 and 2010. The link will be of capacity 1320MW, capable of bi-directional flow, and connected at Grain 400kV substation.
Figure 3.1 illustrates the main changes, since 2000/01, in the generation capacity of transmission contracted plant. For the detail behind the changes, please refer to the tables supplied with this chapter. The remaining Magnox stations will have all closed by the winter peak of 2010/11 and this is taken into account within the capacity reductions of Figure 3.1 . Magnox closures are also reflected in the various tables presented in this chapter. Other than these Magnox closures there are no additional capacity reductions beyond 2003/04. This partly reflects the fact that generators are not required to provide formal notification of disconnections or decommissionings until 6 months prior to the event. The potential high level of activity in 2008/09 referred to previously when considering Table 3.7 is also apparent in Figure 3.1.
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Figure 3.2 illustrates the generation mix from 2006/07 to 2012/13 and includes all transmission contracted generation whether existing or planned (i.e. the 'SYS background'). The customer-based demand forecast of Table 2.1 has been superimposed on the generation mix to give an indication of the apparent surplus of generation over demand Plant Margin. The different fuel types are given in approximate order of economic operation. Please note, however, that this is indicative only and no account has been taken, for instance, of generation availability. Nevertheless, the figure does imply a variation in the type of marginal plant used to meet the demand over the seven years considered. There is a reduction in coal capacity used to meet the demand; not so much in absolute terms, since future as yet unnotified closures are not included, but rather in relative terms. In the later years, the closure of Magnox plant by 2010/11 is offset by the growth in Interconnector, CCGT and Wind generation capacity both in absolute and relative terms.
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In considering the above information it is important to note the following three points:
Figure A.1.1 of Appendix A, gives the geographical location of all transmission contracted Large power stations, whether directly connected or embedded within a distribution system which are existing (as at 2006/07). Directly connected power stations and directly connected External Interconnections with External Systems are also shown. This generation forms the generation background contained within the 'SYS background'. Large power stations which have been formally disconnected (closed) are not shown (see Table 3.10 ) but Large power stations with decommissioned Generating Units are shown (see Table 3.11). Medium and Small power stations and embedded External Interconnections are not shown.
The disposition of the above existing plant, and prospective future plant, in terms of its capacity and location around the system is particularly important when considering the performance (e.g. resultant power flows) of the transmission system, the need for transmission developments and the opportunities for connecting further generation (or demand) to the system see GB Transmission System Performance , GB Transmission System Capability and Opportunities.
When considering bulk transfers of power around the system it is often useful to regard the transmission system as being made up of a number of zones. Such zones and the transmission boundaries between them are described in detail in SYS GB Transmission System. For consistency and ease of explanation, the generation dispositions described in the following paragraphs are also presented on a similar zonal basis.
Figure 3.3a , Figure 3.3b , Figure 3.3c , Figure 3.3d , Figure 3.3e and Figure 3.3f illustrate the change in total installed generation capacity by plant type for regions bounded by four of the main SYS Boundaries over the period 2006/07 to 2012/13. These regions of the system are referred to as Scotland (SHETL), Scotland (SPT), North, Midlands and South. The figures cover all transmission contracted generation (both existing and planned).
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Figure 3.4 summarises the Scotland (SHETL), Scotland (SPT), North, Midlands and South disposition of all transmission contracted generation (both existing and planned) in the years 2006/07 and 2012/13.
The differences between the above spot years are detailed in Table 3.13, which shows a 18.2GW increase in capacity over the period. This change is made up:
Scotland (SHETL):
SHETL TOTAL 3193.5MW
Scotland (SPT):
SPT TOTAL 1824.3MW
NORTH OF SCOTLAND-ENGLAND BOUNDARY 5017.8MW
North:
NORTH TOTAL 924MW
NORTH OF NORTH-MIDLANDS BOUNDARY 5941.8MW
Midlands:
MIDLANDS TOTAL 760MW
NORTH OF MIDLANDS-SOUTH BOUNDARY 6701.8MW
Central:
CENTRAL TOTAL 7177MW
Estuary:
ESTUARY TOTAL 3060MW
South West:
SOUTH WEST TOTAL 1250MW
SOUTH OF MIDLANDS-SOUTH BOUNDARY 11487MW
SYSTEM TOTAL 18188.8MW
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Figure 3.5 illustrates how the disposition of new capacity has developed over the period 2000/01 to 2012/13.
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It should be remembered that Figure 3.3a to Figure 3.3f , Figure 3.4 and Figure 3.5 and Table 3.13 are based on installed generation capacities. However, more importantly, it is the generation actually used in meeting the demand on the day, which determines the power flows at any given time. The 'GB Generation Ranking Order', which is explained in GB Transmission System Performance, is used to determine which generation is operated for the study purposes of this Statement.
By way of illustration, Figure 3.6 shows the Scotland (SHETL), Scotland (SPT), North, Midlands and South disposition of installed generation (also shown in Figure 3.4) together with the regional ACS peak demand disposition. In both 2006/07 and 2012/13, the installed generation in Scotland (SHETL), Scotland (SPT), North and the Midlands exceeds demand, in some areas by a substantial amount. In the South, there is a more even balance in both years with demand exceeding installed generation in 2006/07 and this being reversed by 2012/13. Superficially, this would imply only modest but increasing power transfers across the system.
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However, when the generation expected to be used to meet the demand is considered, a different picture emerges as illustrated in Figure 3.7. Again generation in Scotland (SHETL), Scotland (SPT) and the North exceeds demand in both years. However, in the Midlands and South much of the generation becomes non-contributory (i.e. not used in meeting the demand) such that the demand exceeds generation, by a substantial margin in the South, in both years; implying higher power transfers from the northern parts of the system, through the Midlands to the South. The power transfers at the time of peak under the 'SYS background', are reported in more detail in GB Transmission System Performance.
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Additional information on generation location is given in Table 3.14 and Table 3.15, which show amongst other things, the disposition on the basis of SYS Study Zone and plant type for the years 2006/07 and 2012/13 respectively.
There are a several terms within the Electricity Supply Industry of Great Britain, which are currently used to describe the generation capacity of Power Stations and/or Generating Units. Arguably, the most common of these are:
Declared Net Capability (DNC);l
Registered Capacity (RC);
Transmission Entry Capacity (TEC); and
Connection Entry Capacity (CEC).
Each of the above terms carries a different meaning; some differences are slight whilst others are significant. Definitions or 'descriptions' of these terms are included in the Glossary to this Statement. As a consequence of their different meanings, some are more appropriate for certain uses than others. The following paragraphs provide an outline description of each and summarise how each has been used for the purposes of this Statement.
Declared Net Capability (DNC)
The term DNC is essentially a pre-vesting term. It is no longer used by NGET but, until 2004, was still used by the two Scottish Transmission Licensees (i.e. SPT and SHETL) in their Seven Year Statements. It may be noted that the definition given in the Glossary, which mirrors the definition given in the 2004 SPT SYS, does not define "Generator", although this can be taken to mean either a generating unit or a power station. Nor does that definition define "Auxiliary load" or "site demand", although these may be taken to carry the same meaning
The term DNC is often used to describe the level of electricity sourced from renewable fuels, since the term takes the intermittent nature of the power output from some renewable sources into account. For wind this is 43% of its gross capacity.
Finally, whilst reference may be made to DNC in parts of this Statement, the term is not otherwise used.
Registered Capacity (RC)
The term RC was introduced at vesting and has been in use in England and Wales since then. Its definition has developed over the years and is given in various documents, the most notable of which are the Grid Code (GC) and the Licence Standard. The value of the term has been used in the setting of regulatory, licence and Grid Code requirements. For example, the size of Power Station in terms of RC classifies the station as Small, Medium or Large. That classification, in turn, determines whether the particular plant requires a licence and/or which parts of the Grid Code must be complied with. The current definition is given in the Glossary.
Whilst the definition of RC has been developed over the years since vesting, it is nevertheless very similar in effect to the less rigorous pre-vesting term and definition of DNC used by the Scottish Transmission Licensees. The terms and values of DNC and RC have all been used by the various parties over the years in:
The following provides a quick reference summary of the key properties of RC and its usage within this Statement:
Transmission Entry Capacity (TEC)
The relatively new terms of TEC and CEC were introduced under NETA. In essence, TEC reflects the maximum power the user can export across the GB transmission system away from the connection site. TEC is defined on a station basis only and cannot exceed station CEC. In the GB Grid Code, TEC is defined by reference to the meaning set out in the Connection and Use of System Agreement. This avoids the need to amend the GC when the value of TEC is changed for whatever reason. The Glossary includes an informal description of TEC, which has been written for the purpose of this Statement. The Glossary description is not intended as a formal definition and equivalent descriptions and definitions in other documentation may differ slightly.
Inspection of the description of TEC included in the Glossary section of this Statement reveals that it differs from the Grid Code definition of RC in two respects. First, TEC is solely on a Power Station basis and does not exist on a Generating Unit or CCGT Module basis. Second, the value of TEC represents the net "spill" onto the GB transmission system from the Power Station. Accordingly, any auxiliary demand supplied through the station transformers is netted off the gross station output to give the net "spill".
TEC cannot be greater than Power Station CEC but can be lower since: first, TEC is net of any auxiliary demand supplied through the station transformers; and second, the actual value of TEC can be set for commercial reasons at any lower level. TEC is a commercial term and its value is given in the relevant bilateral agreement.
The following provides a quick reference summary of the key properties of TEC and its usage within this Statement:
Connection Entry Capacity (CEC)
As previously mentioned, the term CEC was introduced, along with the term TEC, under NETA. In essence, CEC is used on both a Generating Unit and Power Station basis. CEC may be regarded as the maximum power that a user may export onto the GB transmission system at the connection site. As with TEC, the GC defines CEC by reference to the meaning set out in the Connection and Use of System Agreement. As previously explained, this avoids the need to amend the GC when the value of CEC is changed for whatever reason. The Glossary includes an informal description of CEC, which has been written for the purpose of this Statement. As with the Glossary description of TEC, the Glossary description of CEC is not intended as a formal definition and equivalent descriptions and definitions in other documentation may differ slightly.
The Glossary description of CEC is in three parts. For each part, i.e. (a) in relation to a Generating Unit, (b) in relation to a CCGT Module and (c) in relation to a Power Station, the relevant value of CEC is written into the bilateral connection agreement.
In the case of (a), the Generating Unit CEC is used as a basis for the design of a new or modified connection. In the case of (c), the Power Station CEC is normally the sum of the individual Generating Unit CECs. A Generator may choose to declare a Power Station CEC, which is lower (but not higher) than the summation of individual Generating Unit CECs, in which case this lower value is written into the bilateral connection agreement.
Inspection of the Glossary description of CEC reveals that it is almost identical to the GC definition of RC and the two may be regarded as being broadly synonymous. The only difference lies in the fact that, on the one hand CEC may include "Maxgen" capability or alternatively it may include a restricted output due to a technical difficulty. RC, on the other hand, is written in terms of "normal full load Capacity". CEC may be regarded as setting the ceiling value on RC.
As mentioned previously, TEC cannot be greater than power station CEC but can be lower.
The following provides a quick reference summary of the key properties of CEC and its usage within this Statement:
Finally, as a related point of interest, PC.4.3.1 of the Grid Code states that, "...NGET will also use the Transmission Entry Capacity and Connection Entry Capacity in the preparation of the Seven Year Statement and to that extent the data will not be treated as confidential".
The GB Grid Code places different requirements on different classes of generating plant. The three main power station classifications are Large Power Station, Medium Power Station and Small Power Station and the Grid Code defines these on the basis of Registered Capacity. The relevant definitions are included in the Glossary section of this Statement. Inspection reveals that the definitions vary according to whether the power station is located on the NGET system, on the SPT system or on the SHETL system. Table 3.1 summarises the differences.
Notwithstanding the fact that the GB Grid Code classifies power stations in terms of their Registered Capacity, for the intents and purposes of this Statement, Power Stations may be taken to be classified and defined in terms of power station Transmission Entry Capacity (TEC).
The definition included in the Glossary of this Statement identifies three types of Bilateral Connection Agreement, namely a Bilateral Connection Agreement (BCA); a Bilateral Embedded Generation Agreement (BEGA); and a Bilateral Embedded Licence Exemptable Large Power Station Agreement (BELLA). Power station projects where these agreements are in place are, as explained in the Glossary, defined as "Transmission Contracted".
Please note, however, that whether "Transmission Contracted" or not, the Distribution Network Operator nets off what he deems an appropriate allowance for the output from embedded Medium and Small power stations from his week 24 Grid Code demand submissions. Accordingly, such power stations are not detailed in this chapter.
Figure 10.5 of Chapter 10 describes the relationships between the different types of Bilateral Agreement, the power station type, the connection type, the power station output terminology and the appropriate charges.
Bilateral Connection Agreement (BCA)
A BCA is for directly connected power stations (regardless of whether they are classified as Large, Medium or Small), directly connected Distribution Systems, Non-Embedded Customers and directly connected Interconnectors.
A User with a BCA pays for both connection to the GB transmission system and for use of the GB transmission system.
A power station covered by a BCA will have both TEC and CEC values.
Bilateral Embedded Generation Agreement (BEGA)
A BEGA, amongst other things, relates to use of the GB transmission system by embedded power stations (which are not License exempt, small power station trading parties and distribution interconnector owners. An embedded power station covered by a BELLA (see below) is not included, as a BELLA relates to Licence exempt embedded Large power stations.
A User with a BEGA does not have a connection to the GB transmission system and, in consequence, does not pay connection charges relating to the GB transmission system. The User does however use the GB transmission system and therefore pays appropriate use of system charges.
A power station covered by a BEGA does not have a CEC since the term CEC relates to the connection assets to the GB transmission system of which there are none. However, a BEGA power station does have a TEC for the purpose of use of the GB transmission system.
Bilateral Embedded Licence Exemptable Large Power Station Agreement(BELLA)
A BELLA is for embedded Large power stations, which are Licence exempt and which are registered either in the SMRS (Supply Metering Registration System) or in the CMRS (Central Metering Registration System) by a User (e.g. host User) who is responsible for the transmission use of system charges relating to the GB transmission system associated with the Balancing Mechanism (BM) Unit registered in CMRS..
A power station covered by a BELLA does not have a connection to the GB transmission system and in consequence does not pay connection charges relating to the GB transmission system. Nor does the power station 'directly' use the GB transmission system since this is via the User referred to above who is responsible for transmission use of system charges associated with the CMRS registered BM Unit. Accordingly a BELLA power station does not pay GB transmission use of system charges. However, payments may change hands between the power station and the User in relation to reduced demand, use of the distribution system etc.
A power station covered by a BELLA neither has, a TEC nor a CEC. The output of the power station is described in Appendix A of the BELLA by the term 'Size of Power Station'.
Licence Exempt Generation Agreement (LEGA)
Arguably, the BCA, the BEGA and the BELLA are generally regarded as the three main Bilateral Agreements. However, a LEGA is a fourth type. This is for power stations capable of exporting between 50MW and 100MW to the total system (i.e. embedded Medium power stations in England and Wales) connecting since 30 September 2000. Such generators may apply to the DTI to seek Licence Exemption. The DTI then consults all interested parties including National Grid. On receipt of the DTI consultation documents we consider the need for:
The above information is included in our response to the DTI consultation document and at the same time we offer a Licence Exempt Generation Agreement with the Generator, also containing the above information, where appropriate. The Bilateral agreements do not automatically subject the Generator to TNUoS charges, but would provide for any necessary data exchange.
A LEGA is, by definition, a Medium power station. In submitting the Week 24 Grid Code demand submissions, the Distribution Network Operator nets off his allowance for the output of Medium and Small power stations. Accordingly, embedded Medium power stations, covered by a LEGA or not, are not detailed in this chapter.
Licence exempt embedded Large (rather than Medium) power stations are covered by a BELLA (rather than a LEGA).
However, please note that following a recent Ofgem decision to approve changes associated with Grid Code Consultation D-05 (Licence Exempt Medium Power Stations), the LEGA will be phased out over the coming year.
Access to the GB transmission system is provided through arrangements with National Grid, acting as GBSO, under the Connection and Use of System Code (CUSC). The CUSC sets out the contractual framework for connection to, and use of, the GB transmission system. The CUSC has applied across the whole of Great Britain since BETTA "go-live" (1 April 2005).
However, prior to BETTA "go-live", the CUSC applied in England and Wales but different arrangements applied in Scotland. The pre BETTA go-live generation offers and agreements between relevant TOs and Users needed to be converted into GB Offers. Condition C18 ("Requirement to offer terms for connection or use of the GB transmission system during the transition period") of Section E ("Transitional Standard Licence Conditions") of the Electricity Transmission Licence placed certain obligations relating to this on National Grid as GBSO. The principal objectives of C18 were to ensure that National Grid, as GBSO, had:
Much consideration has been given to how transmission access rights should be allocated to individual "existing" Users and applicants under BETTA. For this purpose, the parties that needed, or need, to receive GB Offers before and after BETTA go live have been divided into four main GB Offer Groups. These four GB Offer Groups are defined in the Glossary but have been reiterated here for ease of reference.
Group A:
This group includes parties who, at 1st September 2004, were existing Users (i.e. had accepted an Offer).
Group B:
This group includes parties who had applied for connection or use of system prior to 1st January 2005 but who are not in Group A.
Group C:
This group includes parties who applied for connection or use of system in the period from 1st January 2005 to 31st March 2005.
Group D:
This group includes parties who have applied for connection or use of system from 1st April 2005.
As previously explained, in recognition of the uncertainties associated with the future, unless otherwise stated the information presented in this chapter is restricted to existing generation projects and those proposed new generation projects, which are deemed most likely to proceed to completion. Accordingly, proposed future projects, which are classified as "transmission contracted" are included. These would include projects within GB Offer "Group A" and possibly some projects within GB Offer "Group B".
Generation presents information on all the sources of generation which are used to meet the ACS Peak GB Demand as defined in the Glossary and presented in Electricity Demand. Accordingly, Chapter 3 presents information on Large power stations (directly connected or embedded), Medium and Small power stations which are directly connected to the GB transmission system and directly connected External Interconnections with External Systems.
Embedded generation may be Large but is more likely to be either Medium or Small. Large embedded power stations are reported in Chapter 3 as explained above. Medium and Small embedded power stations and embedded External Interconnections with External Systems are reported in this chapter.
Much of the existing and future embedded generation is either in the form of combined heat and power (CHP) projects or in the form of renewable projects. This chapter considers these two types of generation source and, in so doing, reports on large non-embedded renewable sources of generation (e.g. Wind farms).
Superficially, it may seem reasonable to assume that growth in embedded generation could eventually lead to a position of zonal self-sufficiency rendering the GB transmission system redundant in whole or in part. This is not the case and, to understand why, it is first helpful to remind ourselves of the role of the interconnected transmission system and its history.
Until the 1930s, electricity supply in Britain was the responsibility of a multiplicity of private and municipally owned utilities, each operating largely in isolation. The Electricity (Supply) Act (1926) recognised that this was a wasteful duplication of resources. In particular, each authority had to install enough generating plant to cover the breakdown and maintenance of its generation. Once installed, it was necessary to run more plant than the expected demand to allow for possible sudden plant failure.
By interconnecting separate utilities with the high voltage transmission system, it is possible to pool both generation and demand. The interconnected transmission system not only provides for a consistent high quality of supply (e.g. in terms of frequency variations, voltage level, voltage waveforms, voltage fluctuations and harmonic levels) across the system but it also provides a number of economic and other benefits including those outlined in this chapter.
A number of factors influence the decision to construct a power station at a particular location. These include fuel availability, fuel price, fuel transport costs, financing, cooling water, land availability and the level of transmission system charges. For combined heat and power (CHP) stations a local market for the heat output would also be a consideration.
It can be very difficult, particularly for large power stations, to obtain sites close to demand centres for environmental and other reasons. Similarly, renewable energy generation technologies such as wind or wave are unlikely to be located near demand centres. The interconnected transmission system provides for the efficient bulk transfer of power from remote generation to demand centres irrespective of the actual connection voltage of the generation. Transmission of electricity at high voltage is more efficient than transfer at lower voltage due to the lower capital cost per unit transmitted and the lower losses (the 400kV and 275kV GB transmission system losses are approximately 1.5% of energy transmitted).
The interconnected transmission system provides the main national electrical link between all participants (generation and demand) and by linking them via the transmission system it is then possible to select the cheapest generation available. That is, market participants can choose to trade with the most competitive counter party and National Grid, in its role as GBSO Great Britain System Operator) system operator, is able to accept the most attractive 'bids' and 'offers' in the Balancing Mechanism to meet the demand, irrespective of location.
Security in this context means providing the demand customer with a supply of electricity that is continuous (i.e. uninterrupted except in exceptional circumstances) and is of the required quantity and of defined quality (e.g. in terms of voltage, waveform and frequency). This means that the transmission system, and for that matter the generation and distribution systems, must be sufficiently robust to maintain supplies under conditions of plant breakdown or weather induced failures for a wide range of demand conditions.
Interruption of supply can result from insufficiency or unavailability of generation, transmission or distribution capacity. The former is a function of the electricity market. The latter is the concern of the distribution network operators. For transmission, the system is planned and operated in accordance with strict standards laid down in the Transmission Licence.
It may at first seem that security of supply is potentially at its greatest when the source of power is close to the demand it supplies. However, transmission circuits tend to be far more reliable than individual generating units. Accordingly enhanced security is delivered by providing sufficient transmission capacity between customers and the national stock of generation. The transmission system is able to exploit the diversity between individual generation sources and demand.
In an ideal world it would simply be necessary to install generation capacity to meet the forecast maximum average cold spell (ACS) demand. In practice, additional capacity is required for security purposes to cover for one or more of the following reasons: the fact that plant becomes unavailable due either to routine maintenance or breakdown; or plant under construction may not be commissioned on time; the weather may be colder than ACS conditions; or the ACS peak demand forecast may simply be underestimated.
The integrated transmission system enables surplus generating capacity in one area to be used to cover shortfalls elsewhere on the system. The requirement for additional installed generating capacity, to provide sufficient generation security for the whole system, is therefore smaller than the sum of individual zonal requirements.
As a point of interest, before privatisation the Central Electricity Generating Board (CEGB) in England & Wales used a planning margin of 24% to provide generation security when planning the need for future generation installed capacity. Under the pre-NETA electricity "Pool" trading arrangements in England & Wales, capacity payments were paid in respect of available generation capacity. These capacity payments, which were a function of Loss of Load Probability (LOLP), were intended to provide a signal of capacity requirements. Under NETA/BETTA market forces determine the plant margin.
National Grid as GBSO has a statutory obligation to maintain frequency between certain specified limits save in exceptional circumstances (see the Electricity Supply Regulations 1989). Large deviations in frequency can lead to widespread demand disconnections and generation disruptions. System frequency is a continuously changing variable and is determined and controlled by a careful balance between demand and generation. If demand is greater than generation, frequency falls and, if generation is greater than demand, frequency rises.
With the arguable exception of pumped storage power stations, electricity, unlike other commodities, cannot be stored in significant quantities. In order to avoid an unacceptable fall in frequency in the event of the failure of one or more sources of generation, it is necessary to have available additional generation, which can be called upon at very short notice (i.e. within seconds or minutes). This is referred to as 'frequency response'.
Without transmission interconnection, each separate system would need to carry its own frequency response. With interconnection the net response requirement is the highest of the individual system requirements to cover for the largest potential loss of power (generation) infeed, rather than the sum of them all.
The output of most embedded Medium and Small power stations falls into two main categories that are not mutually exclusive, namely that generated for own use, normally in the form of combined heat and power (CHP), and that generated for supply to third parties, mainly from renewable sources (e.g. wind).
A CHP plant is an installation where there is simultaneous generation of usable heat and electrical power in a single process. CHP schemes are generally fuelled by gas, coal or oil although some are also partially fuelled by fossil fuels and partially fuelled by renewable sources of energy (e.g. biofuels such as sewage gas). The latter are referred to as 'Co-firing' generating stations. CHP schemes tend to be located in urban areas close to customers (e.g. large industry) wishing to take the heat output.
Renewable generation technologies cover a wide range of energy sources including hydro, biofuels, wind, wave and solar. In output terms, the largest contributions presently come from hydro (particularly large scale hydro) and biofuels, which include landfill gas, waste combustion, sewage sludge digestion and coppice wood and straw burning. In recent years these two sources have accounted for up to 90% of GB renewable output, with wind making up most of the balance of around 10%, an amount that is projected to increase significantly over the period covered by this Statement.
Electricity Demand considers, amongst other things, the forecast peak demand on the GB transmission system in average cold spell (ACS) conditions which is based on the projections provided by the system 'Users' and by National Grid. ACS peak demand relates to the demand met by directly connected power stations, imports across directly connected External Interconnections from External Systems and embedded Large power stations, all of which are the subject of Generation.
Network operators are required under the Grid Code to net off their own allowance for the output from embedded Medium and Small power stations when submitting their forecasts of demand to be supplied at the Grid Supply Points. They are also required to net off their own allowance for any forecast imports across embedded External Interconnections from External Systems. Accordingly, the output of embedded Medium and Small power stations is taken into account when planning the development of the transmission system. However, this output is not directly seen by the transmission system operator although its overall effect on the GB transmission system and its operation is.
In responding to previous customer surveys, many readers have requested detailed information on embedded generation to be included in the Seven Year Statement. In response to these requests, we have included Table 4.1, which contains a range of information on Small and Medium power stations embedded within distribution networks. Unfortunately, this information is not necessarily complete and, as such, should not be relied up on. In the coming months we shall endeavour to gather a more complete set of data for publication in the 2007 GB SYS. In the meantime, if the reader requires further information they are advised to contact the relevant distribution network operator.
The information in Table 4.1, which relates to the distribution networks in England and Wales, is simply based on an extrapolation of the equivalent information contained in the 2005 GB SYS. This, in turn, was based on information kindly provided by the relevant distribution network operators even though the provision of such detail goes beyond their Week 24 Grid Code obligations. In view of the relatively high volume of data for the distribution systems in England and Wales, a cut-off point of 5MW was adopted to reduce the data collection burden on the distribution network operators (i.e. plant less than 5MW located in England and Wales was not included).
The information relating to the Scottish distribution systems was provided to SHETL and SPT by the Scottish distribution network operators and does not have a lower cut-off level. For User Systems within the NGET and SPT areas, the information is provided on an individual power station basis. For User Systems within the SHETL area, the information is provided on a GSP basis.
There is a Grid Code requirement (PC.A.3.1.4 of the Planning Code refers) for distribution network operators to inform NGET of, inter alia, the summated capacity of embedded Medium and Small power stations within their area. This information is summarised in Table 4.2.
Notwithstanding the fact that the information contained in the above two tables may, in some respects, be incomplete, they do nevertheless provide an initial insight into the types of embedded generation (Table 4.1) and into the total demand in the system (i.e. demand on the GB transmission system plus embedded generation capacity 'netted off ' the distribution network operators Grid Code demand submissions).
Inspection of the two tables indicates that the distribution network operators assume around sixty percent of the installed capacity of embedded generation is considered to be contributing at peak. The contribution assumed by network operators to be firm at other times, including the time of the local peak demand for which the Grid Supply Point is chiefly designed, rather than the time of GB peak demand, is not reported. On the basis of the information provided in Table 4.1, some 50% of the installed capacity of embedded generation is located in the North and Midlands.
In 1993, as part of a programme to reduce carbon dioxide emissions, the government of the time set a target of increasing the electrical capacity of combined heat and power in the United Kingdom to 5GW by the year 2000. After taking office in 1997, the new government endorsed this target, which was reached during 2004. The government subsequently set a new target of 10GW of installed CHP capacity by 2010 as part of its Climate Change Programme to reduce carbon dioxide emissions in 2010 by 20% of their 1990 level.
In addition to the above CHP objectives, in 2002 the government also set a target for 2010 for the proportion of electricity sold by suppliers to be sourced from renewable fuels through the Renewables Obligation (see below). Originally, a capacity target for the United Kingdom of 1.5GW on a declared net capability (DNC) basis, excluding large-scale hydro, was set for the end of 2000. (The term DNC takes the intermittent nature of the power output from some renewable sources into account. For wind this is 43% of its gross capacity.) The 1.5GW target was achieved during 2003.
The main instrument for encouraging the development of renewable generation prior to April 2002, was the Non-Fossil Fuel Obligation (NFFO) in England & Wales and the Scottish Renewable Order (SRO) in Scotland. Under these schemes the Department of Trade and Industry selected and approved renewable generating projects following a tendering process. Electricity suppliers were then obliged to purchase power from these generators, the extra cost of doing so being reimbursed from the Fossil Fuel Levy imposed on customers' bills.
In April 2002, the government's Renewables Obligation (RO) came into force followed by the Renewables Obligation Scotland (ROS) in April 2004. Ofgem administers these schemes on behalf of the Department of Trade and Industry and the Scottish Executive respectively. Since 2002 Ofgem has published three annual reports on the Renewables Obligation and readers are advised to consult these for more detail on the subject. The annual reports are available on the Ofgem website. The size of these obligations increases year on year such that they reach 10% of electricity sales in 2010 and 15% of sales in 2015.
In the their third annual report, Ofgem explain that the government's aim is for renewable energy to make an increasing contribution to energy supplies in the UK, with renewable energy playing a key role in the wider climate change programme. The RO and ROS place obligations on suppliers to source a portion of their supplies from renewable sources. These obligations are referred to collectively as the Renewable Obligation. 'Green Certificates' are issued under the RO and ROS, which certify that a generating station has generated an amount of electricity from renewable sources and that this electricity has been supplied to customers in Great Britain. These are known as Renewables Obligation Certificates (ROCs) or Scottish Renewables Obligation Certificates (SROCs).
An obligation period runs from 1 April to 31 March each year. Suppliers are required to produce evidence to Ofgem of compliance with their Renewables Obligation before a specified day each year. The specified day for the 2004/05 compliance period was 1 October 2005. Evidence can be via ROCs or SROCs. Alternatively, a supplier can discharge its Renewables Obligation, in whole or in part, by paying a buy-out price. The money accrued from this is redistributed to all suppliers in proportion to the amount of renewable power they actually buy, as defined by the number of certificates they hold. The government intends that suppliers will be subject to a Renewables Obligation until 31 March 2027.
When the RO was first introduced, the most prevalent technology type (in terms of the number of accredited generating stations) was landfill gas with 202 accredited stations at 1st April 2002. The number of landfill gas stations being accredited reduced significantly in the first obligation period but increased slightly in the second and third periods. In 2002/03, Ofgem accredited 24 landfill stations in 2002/03 with 31 being accredited in 2003/04. In 2004/05 Ofgem accredited 42 landfill gas stations.
During the third obligation period, the most prevalent technology (in terms of generation capacity) was on-shore wind, followed closely by hydro generating stations with a capability (DNC) less than 20MW followed by landfill generation. The relative proportions of the total renewable capacity installed and accredited under the RO were: Co-firing 29%; On-Shore Wind 22%; Landfill gas 16%; Micro Hydro 14 %; Hydro less than 20MW 13%; Biomass 4%; Sewage Gas 2%; Off-Shore Wind 0.3%; and ACT, Wave and Photovoltaics making up the remainder.
Another instrument of the government's policy to reduce environmental emissions is the Climate Change Levy (CCL). This is an energy tax payable by all industrial and commercial businesses since April 2001. It is levied on energy supplies, the rate varying depending on the fuel, with the levy on electricity being 0.43p/kWh. Energy intensive businesses can receive up to 80% discount on the levy if they enter into agreements with the government to undertake significant energy efficiency improvements.
Electricity generated from renewables is exempt from the CCL, thus benefiting developers of renewable electricity by an extra 0.43p/kWh. As a result, developers of qualifying renewable schemes could receive a minimum support of 3.76p/kWh in 2006/07, (i.e. the buy-out price of 3.324p/kWh under the RO plus the 0.43p/kWh under the CCL). This is in addition to the value of the share-out of the buy-out kitty among those suppliers who have bought green energy under the Renewables Obligation.
The introduction of these two instruments, together with the trading arrangements for the RO certificates, has provided a significant boost to the economics of renewables. However, it is important to also have the successful introduction of an appropriate planning framework in order to facilitate the speedy development and construction of renewable generation in line with the Climate Change Programme and targets.
In presenting our own view of projected peak demand and electricity requirements our assumptions about future growth in embedded CHP and renewable generation are outlined in Electricity Demand.
There are clear indications that there is significant activity associated with the development of wind generation and, accordingly, future activity in this area is worthy of further consideration.
Wind farms may, of course, be embedded or non-embedded and may be classified as Large, Medium or Small power stations. Accordingly, relevant information can be found in two tables presented in this Statement. The first is Table 4.1 which presents information on embedded Medium and Small power stations. Unfortunately, as explained previously, the information contained in Table 4.1 is not necessarily complete and, as such, should not be relied up on. In addition, much of the information has been voluntarily sourced by the various distribution network operators and NGET cannot therefore guarantee its accuracy. The second table is Table 7.1 (of Chapter 7), which presents information on the ranking order and, accordingly, includes information on all Large wind farms, whether directly connected or embedded.
On the basis of the information contained in Table 4.1 , some 260 MW of embedded Medium and Small on-shore wind generation is located in Scotland. As at the data freeze date, there are no off-shore, existing or planned wind farms in Scotland connected, or planned to be connected, to a distribution system or, for that matter, directly to the GB transmission system. Table 4.1 does not indicate any growth in this area.
Table 4.1 also indicates that there is over 1000MW of embedded Medium and Small wind generation located in England and Wales. This roughly divides evenly between on-shore wind (located across the system in the North West, Southwest, Wales and the North East) and off-shore wind located in the North East and the Thames Estuary.
Examination of Table 7.1 indicates a growth in Large on-shore wind farms (embedded or directly connected) from just under 1000MW in 2006/07 to around 5900MW by 2012/13. Some 55% to 60% of this (depending on year) is, or is planned to be connected (embedded or directly connected) within the SHETL area. As previously mentioned, as at the data freeze date, there are no off-shore, existing or planned, wind farms in Scotland.
Table 7.1 also indicates a growth in Large off-shore wind farms (embedded or directly connected) within the NGET area rising from 140MW in 2006/07 to 3445MW by 2012/13. These off-shore farms are located off the coast of East Anglia, the North East coast, the North West coast and the Thames Estuary.
The overall picture indicated by the two tables is of a growth in the installed capacity of wind generation from just under 2.5GW in 2006/07 to over 10.5GW by 2012/13 (made up of 6.5 GW of on-shore wind and 4GW of off-shore wind). Most of the on-shore wind is in Scotland. For example by 2012/13 the prospective capacity in Scotland is around 6GW compared to 0.5GW in England and Wales by the same year. All the off-shore wind capacity indicated is off the coasts of England and Wales.
One effect of an increasing proportion of embedded generation will be to reduce the flow across the interface between the transmission and distribution networks. This will tend to delay the need for reinforcement of parts of the transmission network but it is unlikely to remove the need for the substations that exist at the interface between the transmission and distribution systems (i.e. the Grid Supply Points). These will continue to be required to balance the fluctuations between generation and demand in that specific part of the distribution network from minute to minute.
In a few areas it is possible that embedded generation may increase to a level where there could be electricity exports from distribution networks to the transmission system. Provided such transfers are within the capacity of the super grid transformers, this is not expected to lead to major technical difficulties. The general reduction in the power flow from the transmission to distribution networks does not necessarily lead to a similar reduction in the bulk power transfer across the transmission system. These bulk transfers, and therefore the need for system reinforcements, are a function of the size and geographical location of both generation and demand.
Power stations, particularly Large Power Stations, tend to be located in clusters near fuel sources. This, coupled with their size (i.e. capacity) relative to that of individual demands, means that generation developments (openings or closures) tend to exert the greater influence on the need for transmission reinforcements. Demand changes are normally less localised and are subject to a more even rate of change. Having said that, in some areas (e.g. where demand exceeds local generation) demand can exert the greater local influence and as such there remains a need for accurate demand forecasts in terms of both level and location.
Transmission System Performance, which considers the performance of the GB transmission system against the 'SYS background', includes two figures (Figure 7.3 and Figure 7.4 ) which provide a simplistic overview of the power flow pattern at the time of ACS peak demand for the years 2006/07 and 2012/13 respectively. For ease of reference these figures have been reproduced here as Figure 4.1 and Figure 4.2.
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Power transfers across the system at any given time are a function of the output of the power stations actually operating at that time rather than of their installed capacity. The disposition of such plant changes as the overall demand level changes throughout the year. The predominant north to south power flows illustrated in Figure 4.1 and Figure 4.2 reflect the fact that whilst around 50% of the peak demand is located in the south (i.e. south of the midlands to south border), most of the cheaper generation is located in the north. These heavy transfers from the north to the south prevail throughout most of the year since, as demand falls, less of the relatively more expensive generation in the south is used.
Power transfers across the GB transmission system depend on the disposition of generation and demand regardless of whether it is directly connected GB transmission system or embedded within a distribution system. To reduce bulk flows would require a general movement of economic generation (directly connected or embedded) nearer to the major load centres (e.g. the south). Even then it would not necessarily follow that the north to south power transfers would reduce. For instance, if new embedded generation were to be located in the south its operation could displace the operation of less economic plant also in the south, in which case transfers would be unchanged. Alternatively, if new embedded generation were to be located in the north of the system it is more likely that north to south transfers would increase.
Table 4.1 (on embedded generation) and Table 7.1 (on the ranking order) collectively imply that the installed capacity of wind farms (embedded and directly connected) could reach some 10GW by 2010/11, which would exceed the government's target discussed earlier. However, it has to be borne in mind that not all prospective future projects will necessarily proceed to completion.
It is more useful, therefore, to consider the potential range of impacts on the GB transmission system in general terms against a background of meeting the government's target of 10% of renewables, which equates to 8GW of renewables, by 2010.
If there were to be 6GW of (embedded and/or non-embedded) on-shore wind farms in Scotland, where wind conditions and the prospects for obtaining consents are favourable, and 2GW of (embedded and/or non-embedded) on-shore wind farms in England and Wales, the broad transmission implications would be as follows. There would be a need for reinforcement of the GB transmission system within Scotland to transmit the power from the wind farms to the Scottish load centres but primarily to facilitate the transfers south into England. The capacity of the interconnections between Scotland and England would need to be enhanced and parts of the system in the North West and North East of England would require reinforcement to accept the additional imports from Scotland.
If there were to be 2GW of (embedded and/or non-embedded) on-shore wind in Scotland and 6GW of off-shore wind in England and Wales, the broad transmission implications would be as follows. The off-shore wind may be embedded or non-embedded but is more likely to be directly connected to the GB transmission system than on shore wind farms. Off-shore developments are likely to be located in clusters beyond the 13km exclusion zone but near connection points to the GB transmission system close to the Thames Estuary, the Wash and the North West of England. Given these broad locations, the system effect would be less than in the previous case since flows from Scotland to England would be backed-off. Nevertheless, some transmission development in the Cumbria area could be required and also some reinforcement in the North West to accommodate the 2 GW of on-shore wind in Scotland. While the need for transmission reinforcement, and consequently the cost, would be less, the cost of establishing and connecting the actual off-shore wind farms is likely to be more.
The Balancing and Settlement Code (BSC) and TNUoS charges, including to whom they apply, are explained in Market Overview.
Generators that are not registered within the BSC are exempt from TNUoS charges and payments. Relevant power stations would be Licence exempt, embedded and registered within a Supplier BM Unit. The output of these power stations will have already been accounted for in the supplier's demand figures upon which TNUoS charges are based.
Under the above circumstances an embedded power station which is both licence exempt and not party to the BSC will not be charged TNUoS and may be able to reduce the TNUoS charges payable by the host supplier (i.e. the supplier in whose BM Unit the power station is registered) by generating on the Triad legs.
The output of some renewable technologies, such as wind, wave, solar and even some CHP, is naturally subject to fluctuation and, for some renewable technologies, unpredictability relative to the more traditional generation technologies. Based on recent analyses of the incidence and variation of wind speed, the expected intermittency of the national wind portfolio would not appear to pose a technical ceiling on the amount of wind generation that may be accommodated and adequately managed. However, increasing levels of such renewable generation on the system would increase the costs of balancing the system and managing system frequency.
It is a property of the interconnected transmission system that individual and local independent fluctuations in output are diversified and averaged out across the system. Moreover, the interconnected system permits frequency response and reserves to be carried on the most cost effective generation or demand side service provider at any particular time. These properties of the transmission network permit intermittent/variable generation to be used with lower standby and frequency control costs than would otherwise be the case.
The proportion of conventional generation needed to be retained in the electricity market, given the variable and unpredictable nature of some renewable technologies such as wind, such that current levels of security of supply are not eroded is the subject of the published paper: "A shift to wind is not unfeasible", by Dale, Milborrow, Slark & Strbac, Power UK Issue 109, March 2003.
For example, for 8000MW of wind (e.g. in line with Government's 2010 target of 10% renewables), around 3000MW of conventional capacity (equivalent to some 37% of the wind capacity) can be retired without any increased probability that load reductions would be required due to generation shortages on cold days. However, as the amount of wind increases, the proportion of conventional capacity that can be displaced without eroding the level of security reduces. For example, for 25000MW of wind only 5000MW (i.e. 20% of the wind capacity) of conventional capacity can be retired. This implies that, for larger wind penetrations, the wind capacity that can be taken as firm is not proportional to the expected wind energy production. It follows that the electricity market will need to maintain in service a larger proportion of conventional generation capacity despite reduced load factors. Such plant is often referred to as "standby plant".
Users registered within the Balancing and Settlement Code (BSC) may volunteer to participate in the Balancing Mechanism (BM) regardless of whether they are directly connected to the transmission system or embedded within a distribution system. The minimum offer size in the BM is 1MW.
National Grid's responsibility in the BM is limited to balancing generation and demand and to resolving transmission constraints. This includes a duty and financial incentive under the System Operator Incentive Scheme to purchase Balancing Services economically. The Grid Code requires all embedded participants on the BM to ensure that their physical notifications, bids and offers are feasible with respect to their host network.
The persistence effect of wind and the expected significant diversity between regional variations in wind output means that, while the balancing task will become more onerous, the task should remain manageable. Provided that the necessary flexible generation and other balancing service providers remain available, there is no immediate technical reason why a large portfolio of wind generation cannot be managed in balancing timescales. However, balancing costs would be expected to rise in line with the wind portfolio. We have estimated that for the case with 8000MW of wind needed to meet the 10% renewables target for 2010, balancing costs can be expected to increase by around £2 per MWh of wind production. This would represent an additional £40million per annum, just over 10% of existing annual balancing costs although it is important to highlight that this figure was calculated before a number of recent developments in market rules (e.g. CAP047 Response Pricing) and increases in underlying market costs (e.g. recent rises in generation fuel prices).
In the longer term, we do not think it likely that there will be a technical limit on the amount of wind that may be accommodated as a result of short term balancing issues but economic and market factors will become increasingly important.
Balancing Services (which include Ancillary Services) and Balancing Services Use of System (BSUoS) charges (including to whom they apply) are explained in Market Overview.
National Grid has actively encouraged and facilitated market arrangements for the provision of ancillary services. Whilst BSUoS charges are levied on all BSC signatories, the provision of ancillary services is not limited to those signatories. Accordingly, the provision of such services is open to any party who can provide a service, including embedded generation, cost-effectively.
System operators at the national control centre use ancillary services. They are only able to call-off a limited number of service blocks in the short period of time available. Thus, for practical reasons, de-minimis sizes are specified for control use. These are:
However aggregators/agents are encouraged. This facilitates the provision of practical service blocks, enhances the dependability of service provision and reduces costs due to simplified communication requirements.
Prior to NETA, much experience was gained with a significant number of embedded service providers (generation and demand). However, whilst National Grid now specifies service levels at station terminals rather than at the National Grid/service provider interface, to date it has not been successful in entering into a reactive contract with embedded generation not registered within the BSC. This illustrates the difficulties and costs faced by small reactive providers acting through an intermediate network/distribution system.
Licence exempt embedded generation not registered within the BSC may receive benefits from the host Supplier in recognition of the consequent reduction to that Suppliers obligation to pay BSUoS charges. However, if the embedded generation were to choose to participate in the Balancing Mechanism, then registration within the BSC would be necessary and appropriate BSUoS charges would be levied.
All Generators with Large power stations are obliged to sign onto the Connection and Use of System Code (CUSC). This includes signatories to the Balancing and Settlement Code (BSC). In addition parties who are not holders of a Licence but who have registered within the BSC are also required to sign the CUSC.
The CUSC places a number of obligations on signatories, which includes compliance with the Grid Code. Amongst other things, the Grid Code sets out technical requirements for the various classes of generation (e.g. Large, Medium, Small, embedded and directly connected External Interconnections) as well as requirements for data to be supplied to National Grid as GBSO.
Some of the earlier technologies used in wind turbines were very sensitive to voltage depressions, even where such depressions lasted for very short periods of time, such as the 140 milliseconds that protective equipment on the GB transmission system typically take to remove a line fault caused by lightning. Such faults can result in voltage depressions over an extensive area of the system potentially causing a large number of wind turbines to trip as a result of a common cause. In recognition of this the Grid Code has now been revised to include revised minimum technical characteristics for such generation technologies.
Medium and Small embedded generation which is Licence exempt and which is not registered within the BSC, is not required to sign on to the CUSC and, in consequence, is not obliged to comply with the Grid Code. Nevertheless, it is recognised that such embedded generation does impact on the overall performance of the transmission system and its operation.
Embedded Medium power stations are most likely to have a material effect. Small power stations may also be important particularly if connected at the first voltage transformation level of the Grid Supply Point.
To enable the Transmission Owner's to meet their obligations with regard to planning the transmission system and National Grid, acting as GBSO, to further meet its obligations with regard to operating the GB transmission system it is important that Users submit sufficient and timely information on all embedded generation, which may have a material effect on the transmission system. Amongst other things, the following are required:-
It is also important that relevant embedded generation meets, where appropriate, certain minimum technical requirements (e.g. so that they are able to participate in the provision of ancillary services).
At the time of writing, power station, which are capable of exporting between 50MW and 100MW to the total system in Great Britain, connecting since 30 September 2000 may apply to apply to the Department of Trade and Industry (DTI) to seek a Licence Exemption. The DTI then consults all interested parties including National Grid. Power stations, which are not capable of exporting 50MW or more to the total system, are automatically exempt from the requirement to hold a generation licence. On receipt of the consultation documents from the DTI, we consider the need for:
The above information is included in our response to the DTI consultation document and at the same time we offer a Licence Exempt Generation Agreement Market Overview with the Generator, also containing the above information, where appropriate. The Bilateral agreements do not automatically subject the Generator to TNUoS charges, but would provide for any necessary data exchange. Please note however that, following Ofgem approval of changes to the Grid Code in relation to Licence Exempt Embedded Medium power stations, the requirement for LEGAs will be phased out during the course of this year.
It is recognised that some Generators with embedded generation would not want to have a contract or any other commercial arrangement with National Grid. The longer term solution to these interface issues with embedded generation is for National Grid to work with the host distribution network operators to obtain the necessary information, ensure co-ordination of developments and also to pass across certain technical responsibilities, currently in the Grid Code, to the network operator. This approach would facilitate a single contract relationship between the embedded generation and the host distribution network operator.
National Grid recognises the importance of climate change issues and that the government's targets for growth in CHP and renewable generation are likely to lead to a continuing growth in embedded generation. It is important for National Grid to play its part in facilitating this growth by ensuring that any transmission issues arising are appropriately addressed. At present, no insurmountable transmission problems associated with accommodating new embedded generation projects are foreseen. Indeed, the properties of the interconnected transmission system are such as to facilitate embedded generation growth regardless of location.
Nevertheless, this does not preclude the potential need for reinforcements to the GB transmission system, the extent of which would be a function of the system location of the new plant. For example, the extent, and therefore cost, of GB transmission reinforcement would be a function of the volume of off-shore wind located off the England and Wales coast or on-shore wind located in Scotland.
The persistence effect of wind and the expected significant diversity between regional variations in wind output means that, while the balancing task will become more onerous the task should remain manageable. Provided that the necessary flexible generation and other balancing service providers remain available, there is no immediate technical reason why a large portfolio of wind generation cannot be managed in balancing timescales. However, balancing costs would be expected to rise in line with the wind portfolio. We have estimated that for the case with 8000MW of wind needed to meet the 10% renewables target for 2010, balancing costs can be expected to increase by around £2 per MWh of wind production. This would represent an additional £40million per annum, just over 10% of existing annual balancing costs although it is important to highlight that this figure was calculated before a number of recent developments in market rules (e.g. CAP047 Response Pricing) and increases in underlying market costs (e.g. recent rises in generation fuel prices).
In the longer term, we do not think it likely that there will be a technical limit on the amount of wind that may be accommodated as a result of short term balancing issues but economic and market factors will become increasingly important.
This chapter brings together information on generation capacity from Generation Capacity and forecast ACS (average cold spell) unrestricted peak demand from Electricity Demand and examines the overall plant/demand balance on the GB transmission system by evaluating a range of potential future plant margins.
However, it is emphasised that none of the plant margins presented in this chapter is intended to represent our forecast or prediction of the future position. The primary purpose is rather to provide sufficient information to enable the readers to make their own more informed judgements on the subject.
The plant margins presented have been evaluated on the basis of a range of different backgrounds. These backgrounds take some account of the uncertainties relating to future generation, which include: the relative likelihood of prospective new future generation projects proceeding to completion; as yet un-notified future generation disconnections (closures); and the possible return to service of previously decommissioned plant (or the return to service of plant with TEC currently set at zero). The appropriate contribution towards the plant margin of generation output from wind farms is also considered, as is the potential effect on the plant margin of the sterilisation of generation capacity by virtue of its location behind a transmission constraint.
There are a number of definitions of plant margin in current usage; and each definition is appropriate to a particular purpose. Naturally, the calculated value of plant margin also varies along with the definition. A discussion of two of the most useful definitions is included in the section headed Plant Margin Terminology, which is located towards the end of the chapter. That section also contains other related explanatory information and readers, who are unfamiliar with current terminology, are advised to first read that section before returning to the main body of the chapter.
The chapter concludes with a brief report on the related issue of gas and electricity market interaction.
Unless otherwise stated the network analyses (e.g. the illustrative power flows, the loading on each part of the GB transmission system and the fault levels) presented in this Statement are based on the SYS background. Amongst other things, the SYS background includes existing generation projects and those proposed new generation for which an appropriate Bilateral Agreement is in place. This would include projects within GB Offer "Group A" and possibly some projects in GB Offer "Group B". Accordingly, most of the studies and analyses presented assume that the full 18.2GW of generating plant planned for commissioning over the period from the 2006/07 winter peak to the 2012/13 winter peak, will commission.
However, unless plant is already under construction there can be only limited certainty that any particular project will proceed to completion and, accordingly, there are a number of areas of uncertainty relating to the future generation position and consequently the future plant/demand position. These include:
In view of these uncertainties, three generation backgrounds have been considered. Each has been selected in recognition of the different level of certainty relating to whether the proposed new transmission contracted plant will, in the event, proceed to completion. These are illustrated in Figure 5.1.
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This background includes the existing generation and that proposed new generation for which an appropriate Bilateral Agreement is in place. This would include projects within GB Offer "Group A" and some projects in GB Offer "Group B". The fact that a generation project may be classified as 'contracted' does not mean that the particular project is bound to proceed to completion. Nevertheless, the existence of the appropriate signed Bilateral Agreement does provide a useful initial indicator to the likelihood of this occurring.
A second useful indicator is whether plant has already been granted the necessary consents under Section 36 (S36) of the Electricity Act 1989 and Section 14 (S14) of the Energy Act 1976 (see Market Overview). This background includes all existing plant, that portion of plant under construction that has obtained both S36 and S14 consent where relevant, and planned future plant that has obtained both S36 and S14 consent where relevant. Any 'contracted' generation not already existing that requires S36 and S14 consent but has not obtained both is excluded from this background.
This background is essentially the same as background 2 but excludes all future generation plant not yet under construction.
Table 5.1 , Table 5.2 and Table 5.3 set out the plant/demand balances for each of the three generation commissioning backgrounds on the basis of the customer based unrestricted demand forecasts given in Electricity Demand. The forecast demand streams utilised in each of these tables exclude station demand as that element of demand is excluded from the station TEC.
Table 3.7 and Table 3.8 of Chapter 3 identify, amongst other things, which new 'transmission contracted' generation since 2000/01 is either existing by 2006/07 (7.4MW) or under construction (1.5GW). The tables also show how much of the remaining new 'transmission contracted' generation has, where relevant, obtained the necessary S36 and S14 consents (1.5GW) and how much has yet to obtain consent (17GW).
Table 5.4 and Figure 5.2 compare plant margins derived from the customer based demand forecast with those derived from our own base view of future demand growth given in Table 2.5. This is repeated for each of the above backgrounds to give six sensitivities in all.
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Generators are only required to give 6 months notice of closure of existing plant, which means that it is possible for us to receive formal notice of closure of plant within the first year of this Statement. It is important to read the Quarterly Updates to this Statement to identify any changes since the data was frozen for this GB SYS on 1 December 2005.
The effect on the potential future plant margin of a particular assumption on future generating closure may, of course, be readily assessed. For example, if it were assumed that say 1GW of additional generating plant were to decommission (close) by the year 2012/13 (i.e. when the demand less station demand is some 68GW), the Plant Margin in that year would obviously reduce by around 1.5 percentage points (i.e. 100*1GW/68GW = 1.47%) relative to the margins shown in Tables 5.1 to 5.4 and the related figures.
Table 3.11 lists generating units, which have either been formally notified by the owner as decommissioned (effectively TEC=0) or simply notified zero TEC covering the seven year period of this Statement; the total capacity of this plant is just over 3.4GW. Some, or all, of this plant has been retained by its owners for commercial reasons (e.g. placed in reserve or mothballed) and may under certain circumstances be returned to service at some future date (see Decommissionings).
However it is unlikely that all this capacity could be returned to service. Of the 3.4GW, perhaps some 500MW to 1GW has the greatest potential to return to service. Even then, it should also be borne in mind that, were individual plants to be re-commissioned/returned to service, the full previous capacities may not necessarily be realised.
The effect on the potential future plant margin of a particular assumption on re-commissioning generating units may again be readily assessed. For example, if it were assumed that say a 500MW unit were to re-commission by the 2012/13 winter peak, the plant margin in that year would obviously increase by around 0.7 percentage points (i.e. 100*0.5GW/68GW) relative to the margins shown in Tables 5.1 to 5.4 and the related figures.
The broad system effect of recommissioning mothballed plant is a function of the size and location of the particular plant or tranche of plant. The effects of returning individual plant to service must necessarily be considered on an individual basis both in terms of the overall system impact and on a site specific basis.
The section headed Plant Margin Terminology presented later in this chapter explains that the definition of Plant Margin, used for the purposes of this Statement, is such that no allowance is made within its calculation for the intermittent nature of the output and the level of output that, in consequence, can be relied upon from wind power plants at the time of system peak. This is unlike the assumptions on wind plant output underlying the system analyses, which are presented and discussed in Modelling of the Planned Transfer and in GB Transmission System Capability.
However, to enhance transparency and promote greater understanding within this chapter, additional plant margins have been calculated for a range of assumptions on the availability of wind generation capacity at the time of the winter peak. Nevertheless, it should be remembered that such a range is quite arbitrary in this plant margin context.
Table 5.5 and Figure 5.3 display plant margins for wind capacity availability assumptions of 80%, 72%, 60%, 40%, 20% and 0%. The SYS background (i.e. with an inherent 100% wind capacity assumption), as given in Figure 5.2 and Table 5.1, is also included for ease of comparison. Please note that the 72% has been chosen as it is consistent with the level of availability assumed within the power flow analyses as described in Chapter 7.
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Transmission congestion exists on certain parts of the GB transmission system and this is considered in Chapter 8("8_0","GB Transmission System Capability"). Congestion occurs when the transfer capability of certain parts of the transmission system is insufficient to carry the power transfers arising from the unconstrained operation of generating plant. In such circumstances, generation is either constrained on or constrained off to avoid violation the Licence Standard in relation to system operation. Plant, which is constrained off, may be considered to be 'sterilised' in that it is unable to contribute to meeting the demand and may therefore be regarded as non contributory towards the overall GB plant margin.
Recent and forecast growth in generation in Scotland is significant, partly due to the high volume of new renewable generation seeking connection in the area. Until sufficient transmission reinforcement works are in place to enhance transmission capability across the boundaries between the SHETL system, the SPT and the NGET system the very low opportunities for the connection of new generation in the northern parts of the system will remain.
As a generalised illustration, if it were assumed that say 1.2GW of generating plant in Scotland were constrained off at the time of the 2006/07 peak to limit the power flows from Scotland into England to within acceptable levels, then this would effectively reduce the overall GB plant margin, in that year, by around 1.9 percentage points (i.e. 100*1.2GW/63.1GW).
It is worth repeating that, while plant margins based on several backgrounds have been considered, we do not attach any probability to the likelihood of occurrence of any particular background, including the SYS background. The range of backgrounds has been considered to enable readers to form their own view on potential future plant margins and do not represent our predictions of the future outcome.
The next section of this Plant Margin Terminology explains that a margin of installed generation capacity over peak demand is necessary for security of electricity supply and is not surplus or excess capacity. That section also explains that, for the purpose of calculating plant margins, power station TEC has been used. Power station TEC is net of station demand. Accordingly, the demand used in the calculation also excludes station demand.
The margins shown in Figure 5.2 and Table 5.4 do not assume any plant is removed from service through disconnection or added through the return to service of currently unavailable (or decommissioned) plant. For margins calculated using the customer-based demands, the 'SYS background' shows margins rise progressively from around 21% in 2006/07 to 39% in 2012/13. Under the 'Consents Background' the margins the margins fall from the initial 21% to around 14% by the end of the period. Margins for the 'Existing and Under Construction background' fall more sharply to 11% by 2011/12.
Margins calculated using the National Grid based forecast demands are, in general, higher than those calculated using the User-based demands. The plant margins calculated on the basis of reduced wind availability assumptions, which are shown in Table 5.5 and Figure 5.3, are also naturally lower. As a point of interest, the relatively high level of activity in 2008/09, previously discussed in Generation Capacity Additions, is a common feature of all cases.
The margins for 2006/07 should be viewed against the background of higher certainty (e.g. relating to demand forecasts and plant availability) associated with the earlier years. Thus, a lower margin in the earlier years may provide the same level of generation security as a higher apparent margin in later years.
When reduced availability in wind farm output is taken into account, the apparent margins are naturally reduced significantly as illustrated in Figures 5.3 and Tables 5.5. The potential for sterilised generating plant due to transmission congestion has the potential to further reduce margins.
Finally, it is stressed that none of the margins presented can, at this stage, be said to be 'correct'. However, the most probable margins are considered to be captured by the wide range given. This range of backgrounds, qualified by comments on potential closures, possible terminations, the possible return to service of plant that is currently unavailable and the potential sterilisation of generating plant, may assist readers in formulating their own views on the subject.
As a result of the various uncertainties, not all of which have been reported in this chapter, there is the potential for a wide range of possible outcomes relating to generation. As a consequence, we have developed our own view of the likely developments into the future, which is considered alongside the SYS based backgrounds when undertaking our investment planning processes.
In developing our own view of available generation capacity going forward, we have made an assessment of the potential impact of a number of physical, environmental and commercial drivers. The physical drivers include the ageing population of certain classes of generating plant. Environmental drivers include the impact of the introduction of the EU Emissions Trading Scheme (ETS) from 2005, the Large Combustion Plant Directive (LCPD) from 2008 and the development of large scale (>100MW) off-shore wind farms. Commercial factors, which are entwined with the drivers outlined above, include the impact of forward prices, generator rationalisations, mothballing of plant and ancillary services. In addition, developments in the commercial framework would influence the generation capacity available.
In simple terms, the 'plant margin' is the amount by which the installed generation capacity exceeds the peak demand. Thus a system with a peak demand of 100MW and 120MW of installed generation has a 20MW plant margin, which represents 20% of the peak demand.
Some commentators assume that the plant margin is surplus or excess generation, which is not necessary to the power system. This is incorrect since generating units are subject to breakdown and need to be taken out of service from time to time for maintenance and repair. Generating units are not available to generate 100% of the time.
If it is assumed that only 85% of the total stock of generating plant could be predicted to be available at the time of winter peak demands several years ahead, then it would be necessary to plan to meet that peak demand (100%) with only 85% of the generation. This would mean that an installed generating capacity equivalent to about 118% of the peak demand (i.e. 100 ÷ 0.85) would be needed in order to meet the peak. Further allowances would also have to be made for other factors such as the risk that the weather might be colder than the Average Cold Spell (ACS) conditions on which demand forecasts are based.
It was for reasons such as these that, in the past, large integrated power system utilities (e.g. the Central Electricity Generating Board in England and Wales) sought to achieve a plant margin of some 24% several years ahead of the event. This margin was referred to as the 'planning margin' rather than 'plant margin' (i.e. the planning margin was the value of plant margin used for planning the need for future generation).
An appropriate minimum value of 'plant margin' is therefore necessary for the security of electricity supply and does not represent surplus or excess generation. The actual required value of plant margin will be a function of the characteristics of the power system to which it applies.
The higher certainty associated with short term forecasts of say demand and generating unit availabilities means that the same level of security of electricity supply can be achieved with lower plant margins. Accordingly, the required margin for the earlier years would be much lower and the operational planning margin requirement for real time generation is generally around 10% depending on prevailing circumstances.
This chapter focuses on the planning time phase and relates to the security of supply provided by the generation capacity that is either already installed or is planned to be installed. The operational time phase, which relates, amongst other things, to the actual availability of the installed generation on the day, has not been specifically addressed.
In the privatised electricity supply industry within England and Wales and Scotland, there is no set standard for the planning margin and the need for new plant is determined by market forces.
Plant Margin is defined in different ways in different documents.
The term "Plant Margin" is used in the License Standard, GB Transmission System Security and Quality of Supply Standard (SQSS). In Appendix C of that document, its value is used to determine whether the Straight Scaling and/or the Ranking Order technique should be used in the evaluation of the Planned Transfer Condition. The SQSS definition of Plant Margin is:
"The amount by which the total installed capacity of directly connected Power Stations and embedded Large Power Stations exceeds the net amount of the ACS Peak Demand minus the total imports from External Systems. This is often expressed as a percentage (e.g. 20%) or as a decimal fraction (e.g. 0.2) of the net amount of the ACS Peak Demand minus the total imports from External Systems".
Whilst this definition is considered appropriate for the License Standard, it is not necessarily appropriate for other uses. When considering the Plant Margin of a particular Utility or group of Utilities it is more appropriate to consider the simple relationship between total installed generation capacity and peak demand. The current GB SYS definition is given in the Glossary but is repeated below for ease of reference:
"The amount by which the total installed capacity of directly connected Power Stations and embedded Large Power Stations and imports across directly connected External Interconnections exceeds the ACS Peak Demand. This is often expressed as a percentage (e.g. 20%) or as a decimal fraction (e.g. 0.2) of the ACS Peak Demand".
The difference between the above two definitions lies in the fact that, the License Standard definition treats imports as negative demand but the GB SYS definition treats imports as generation. Whilst the plant margin in MW terms remains the same, in percentage terms the GB SYS margins are lower than would be the case using the License Standard definition. Please note that, whilst the wording of the GB SYS definition of plant margin does not mention exports to External Systems, it is implicit that such exports should be treated as positive demand.
The question arises as to whether the installed generation capacity used for the purpose of the plant margin calculations in this Statement should be reduced in recognition of the high levels of future renewable generation which have inherently low availability (e.g. wind farms).
It has already been explained that the plant margin relates to the security of supply provided by the level of generation installed on the system to meet the demand. The "planning margin" is the value of plant margin calculated to be required several years ahead of the event to achieve the desired level of security at the time of the forecast winter peak demand. The chosen value of "planning margin" stochastically takes account of: the average winter peak availability of all generation; variations in the assumed average generation availability; variations in forecast peak demand due to weather; and basic forecasting error.
The selected value of the planning margin does not influence the definition or the calculation of the plant margin but rather the level of security it provides (derived from stochastic calculations). In view of this, for the purposes of this Statement, the installed generation capacity has not been reduced to compensate for low availability of renewable generation when calculating the basic plant margins.
However, to enhance transparency and promote greater understanding within this chapter, additional plant margins have been calculated for a range of assumptions on the availability of wind generation capacity at the time of the winter peak.
It may be argued that the "total installed capacity of a power station" is the aggregate of the Registered Capacities (or CEC) of all the individual Generating Units at that Power Station. However:
Although TEC of a power station does not strictly fall within the definition of "total installed capacity", to the intents and purposes of this 2006 GB SYS it is reasonable to take TEC as being equal to the "total installed capacity" of a power station. Accordingly, the plant margin has been calculated on the basis of TEC.
By definition, TEC is a gross-net-net quantity. That is it is net of power supplied through the Generating Unit's unit transformer and net of the auxiliary demand supplied through the station transformers. However, the "ACS Peak GB Demand" includes station transformer demand.
Accordingly, to avoid double counting in the calculation of plant margin, the demand to be used should be "ACS Peak GB Demand" less "station demand" at peak.
Accordingly, for the purposes of this Statement, the plant margin has been calculated on the basis of:
The interconnected electricity transmission system in Great Britain provides for the efficient bulk transfer of power from sources of electricity generation to the demand centres. The main benefits of the GB transmission system are outlined in The Benefits of an Interconnected Transmission System . Amongst other things, the transmission system provides for power stations to be located remote from the demand centres. The choice of power station location would take account of a wide range of considerations including financing, environmental factors, land availability, fuel availability and cost, potential savings in fuel transportation costs as well as taking account of our Transmission Network Use of System (TNUoS) charges which we levy on our customers for making use of our transmission system. Transmission Network Use of System charges are described in Market Overview.
Amongst other things, Generation Capacity reports on both the growth in capacity and disposition of Large power stations and the import capability of directly connected External Interconnections. The installed capacity of such plant is set to rise from 76.3GW in 2006/07 to 94.5GW by 2012/13. By 2012/13 it is projected that CCGT capacity will exceed coal capacity by 4.6GW and will account for 35% of the total installed transmission contracted generation capacity.
Gas is transported from producer to gas consumer (e.g. CCGT power station) via National Grid's gas transmission network for which transportation charges are levied. Thus, CCGT power stations could be viewed as a producer on the electricity transmission system and a consumer on the gas transmission network. This dual role gives rise to a degree of interaction between the electricity and gas markets. In particular, there are two elements in the gas market that have the potential to affect the level of available generation capacity: 'interruptible gas services' and 'CCGT arbitrage':
This is a service National Grid Gas offers to its customers which provides for lower gas transportation charges but, at times of high gas demand, allows it to shut off some or all of the gas supplied to the supply point for a specified maximum number of days within a year.
Gas supply could be interrupted by National Grid when there are transportation constraints on the National Gas Transmission network. In addition Shippers or Suppliers of gas can commercially interrupt their customers (e.g. CCGT station) either to balance their demand and supply portfolios or to sell gas onto the open market.
However, the majority of power stations that would be affected (i.e. those with interruptible gas supplies) have back up supplies of distillate oil. Thus, providing there are no technical problems relating to switching to and from distillate oil, and providing adequate distillate capacity is available, then electricity generation can be maintained.
Gas-fired stations have the potential to respond to market price signals, decreasing their gas consumption when the electricity price is lower than the price of burning gas. This ability to arbitrage between gas and power is not restricted to power stations with National Grid gas interruptible contracts, with some recent experience of firm CCGTs commercially self-interrupting over the 2005/06 winter.
The willingness of the CCGTs to commercially interrupt themselves will be determined by the spark spread, which is itself influenced by the ability of the power generation sector to switch to other fuels and the level of electricity demand. Given the within-day profile of electricity demand, there is more scope for gas-fired generators to reduce their gas demand outside the peak half-hours of the day, as well as at other times of low electricity demand, such as at weekends and during holiday periods and either burn alternative fuel or switch generation to another station, burning coal or oil, within their portfolio of stations.
National Grid have carried out a detailed analysis to estimate the potential extent of CCGT arbitrage/demand side response within England and Wales, the results of which can be found in our 2005/06 Winter Outlook Report published in October 2005. http://www.ofgem.gov.uk/temp/ofgem/cache/cmsattach/9041_24304b.pdf
Looking forward, we think that there is a strong case for all prospective new CCGTs to fit alternative fuel capability in order to provide additional flexibility to deal with periods of gas-electricity interactions, especially given the projected increase in gas' share of the electricity generation market.
This chapter describes the existing and planned GB transmission system in terms of the electrical parameters of its components, its electrical and geographical structure and its planned development over the period to 2012/13. The chapter identifies the generation and demand tariff zones, which are used in the Transmission Network Use of System (TNUoS) charging process. To complete the picture, the chapter also reports on the main system boundaries which are used to illustrate the overall capability of the transmission system to transmit power and on the associated study zones used in the various technical analyses contained in this Statement.
In view of the volume of transmission system data presented in this chapter, most of the figures and tables are presented in Figures and Data and only referenced in the text. As explained in the Introduction such figures and tables have accordingly been prefixed with the letter 'A' or 'B' as appropriate (e.g. Figure A.1.2).
The latter part of this chapter provides some basic introductory material relating to the GB transmission system including some general power station statistics and a layman's to some of the technical material used in the main text. The aim is to provide readers, unfamiliar with aspects of power systems, with some basic information to facilitate a better understanding of the material contained in the Statement.
The existing and planned GB transmission system described in this chapter, together with the customer-based demand forecasts described in Chapter 2 and the existing and planned generation background described in Chapter 3, form the basis of the SYS background upon which most of the studies and analyses presented in this Statement are based. These three elements of the SYS background (namely: demand; generation; and transmission) are internally consistent. For example, the transmission background of this chapter includes all transmission connection developments cited explicitly in the relevant Bilateral Connection Agreements as being necessary to permit the connection of the generation contained in the generation background of Chapter 3. It is worth repeating, however, that the SYS background does not include any transmission development that may be needed to accommodate prospective projects of new generation or demand, which do not have an appropriate Bilateral Agreement in place on the Data Freeze Date of 1 December 2005.
In view of the uncertainty associated with future developments (particularly that relating to future transmission contracted generation), the timing of construction of infrastructure reinforcements is managed such that investments are made to well defined requirements. This means that in some cases construction is deferred to the last moment to avoid the risk of undertaking investments which may turn out to be unnecessary (e.g. where transmission contracted generation does not in the event proceed to completion), while at the same time ensuring that an efficient, co-ordinated and economic system, compliant with the Licence Standard is provided as required by the Transmission Licences.
Accordingly, the SYS background, upon which the bulk of this Statement is based, does not necessarily contain all the transmission reinforcement schemes that may in the event be required for compliance with the Licence Standard. This chapter focuses on the transmission network of the 'SYS background' which comprises the existing network together with those planned future transmission developments which are considered least likely to be varied to meet the changing needs of the system as it evolves.
Planned transmission developments may include:
The GB 400kV, 275kV and 132kV transmission system for the winter of 2005/06 (as at the data freeze date of 1 December 2005) is shown geographically in Figure A.1.2. Table 6.2 lists the main planned developments to the transmission system in each year up to 2011/12. This table is complemented by the power flow diagrams in Power Flows.
Network parameter values for the existing and planned 400kV, 275kV and 132kV transmission system are included in Appendix B:
Substations are referred to in some tables and figures by a 5 or 6 character code. The first four letters of the code refer to the site name and are listed in Table B.1a (for SHETL), Table B.1c (for SPT) and Table B.1c (for NGET). In other parts of this Statement, a fifth and sixth character is added. In these cases, the fifth character refers to the voltage level as follows:
For example Feckenham 400kV has code FECK4.
For non-generator bus bars, the sixth character of the bus bar name is chosen to provide information about the bus bar. In general, a value of Ɔ' represents a solid bus bar. Bus bar sections which are capable of being coupled but which are run separate due to fault level or load flow reasons, are given characters other than zero.
The three tables also show Demand and Generation Use of System Charging zones and the low voltage shunt susceptance at each node as supplied by users. The information contained in Table B.1c relates to the NGET 400/275kV transmission system. NGET own a number of bus bars at lower voltages, which are embedded within distribution systems. For the purposes of this Statement these assets are not considered to be part of the GB transmission system but, nevertheless, Table B.1c does list these lower voltage bus bars. For further information on this, users should contact National Grid as explained in Further Information.
These tables list the parameters of all circuits for each of three transmission companies (SHETL, SPT and NGET respectively), including length, type (overhead line or underground cable), resistance, reactance, susceptance and post fault continuous seasonal ratings. Please note that circuit lengths are indicative only as they do not include detail such as 'cable entries' at substations. The information contained in Table B.2.1c relates to the NGET 400/275kV transmission system. NGET own a number of circuits at lower voltages which are embedded within distribution systems. For the purposes of this Statement these assets are not considered to be part of the GB transmission system. Nevertheless, Table B.2.1c lists these lower voltage circuits. For further information users should contact National Grid as explained in Further Information.
The actual electrical connections between circuits at the substation are commonly referred to as the substation 'running arrangement'. Please note that whilst Table B.2.1a , Table B.2.1b and Table B.2.1c assume particular running arrangements for the various substations on the system, these may be subsequently varied for instance to reduce fault levels.
These tables list the planned changes to the circuit parameters for each of the three transmission companies over the period from 2007/08 to 2012/13. The year of the change is also given together with the new parameter values.
These tables list the parameters of all grid supply transformers for the three transmission companies together with their nominal ratings (in MVA).
These tables list typical transformer, Static Var Compensator and quadrature booster parameters respectively for the three companies. For exact values at a particular site, users should contact the relevant transmission company as explained in Further Information.
These tables give information all reactive compensation plant owned by the three transmission companies, together with Mvar capabilities. The system location of this plant is indicated in Figure A.2.4 , Figure A.3.4 and Figure A.4.4.
These tables list the planned changes to reactive compensation for each of the three transmission companies over the period from 2007/08 to 2012/13. The year of the change is also given together with the new parameter values.
These tables list indicative circuit breaker ratings for the three transmission companies.
The existing 2006/07 GB transmission system is shown schematically in Figure A.2.1 for SHETL, Figure A.3.1 for SPT and Figure A.4.1 for NGET. Looking forward, the GB transmission system as projected for the 2012/13 peak, including planned main extensions, is shown schematically in Figure A.2.3 for SHETL, Figure A.3.3 for SPT and Figure A.4.3 for NGET. As previously mentioned, the planned extensions include transmission connection developments cited explicitly in the relevant Bilateral Connection Agreements as being necessary to permit the connection of the generation contained in the generation background of Chapter 3. It is worth repeating, however, that the SYS background, and hence the figures, does not include any transmission development that may be needed to accommodate prospective projects of new generation or demand, which do not have an appropriate Bilateral Agreement in place on the Data Freeze Date of 1 December 2005.
The above schematic figures are complemented by the schematic power flow diagrams, which cover each winter peak from 2006/07 to 2012/13 inclusive and are presented in Power Flows. The power flow diagrams also highlight planned developments in each year over the period. However, such planned developments are only shown in so far as they affect the figures. In addition, please note that the substation 'running arrangements' reflected in this series of figures are subject to variation (see Table B.2.1a , Table B.2.1b and Table B.2.1c ). Table 6.2 provides a more complete description of developments some of which may not be reflected in the power flow diagrams in Chapter ("C_1","Power Flows").
As mentioned previously, the system location of reactive compensation plant, which is projected to be in existence by 2012/13, is shown schematically in Figure A.2.4 for SHETL, Figure A.3.4 for SPT and Figure A.4.4 for NGET. For details of additional reinforcement schemes, not forming part of the 'SYS background', which may be necessary for full compliance with the Transmission Licence security standards, please refer to Table 8.2 and Indicative Reinforcements for Licence Compliance.
Transmission Network Use of System (TNUoS) charges reflect the cost of installing, operating and maintaining the GB transmission system (see Market Overview. The basis of TNUoS charging is the Investment Cost Related Pricing (ICRP) methodology introduced in 1993/94.
Generation TNUoS Tariff Zones
There are 21 generation TNUoS tariff zones defined in such a way as to meet the criteria for defining zones set out in the ICRP methodology. These criteria broadly require that: first, zones should contain nodes whose marginal costs fall within a specified narrow band; and second, nodes within zones should be both geographically and electrically proximate. The 21 generation TNUoS tariff zones are depicted geographically in Figure A.1.3 against a backdrop of the 2006/07 GB transmission system.
Demand TNUoS Tariff Zones
There are 14 demand TNUoS tariff zones, which correspond to the original Regional Electricity Company (REC) franchise areas in England and Wales, and the geographical areas of the two Scottish electricity companies. These are again depicted geographically in Figure A.1.4 against a backdrop of the 2006/07 GB transmission system.
General Interpretation
Both Figure A.1.3 and Figure A.1.4 only provide an approximate indication of the geographical area of the tariff zones. Formally, it is only the transmission substations that are allocated to zones and the figures should not therefore be used to establish the zone of any particular town or village. A demand customer's zone is effectively determined by the Grid Supply Point (GSP) Group to which the customer is deemed to be connected. In the case of a directly-connected power station, the generation tariff zone applicable relates to the geographical location of the transmission substation (connection site) to which the station is connected. In the case of an embedded power station, the generation tariff zone applicable relates to the transmission substation to which that station is deemed connected. This would depend on the operating arrangements of the lower voltage distribution networks under the control of the local distribution Network Operator.
The geographic picture provided by Figure A.1.3 is complemented by Figure A.2.2 for SHETL, Figure A.3.2 for SPT and Figure A.4.2 for NGET, which present the generation tariff zones against the 2006/07 schematic/electrical backgrounds of each Transmission Area.
Table 2.2a lists the 2006/07 maximum demand for each GSP and was introduced in Electricity Demand. The final column in the table also gives DCLF (Direct Current Load flow) Node information. This has been included to increase the transparency, particularly with regard to the use of GB SYS data in the DCLF Transport model, which is used for calculating TNUoS tariffs. Whilst the information provided allows Users to identify the DCLF nodes at which LV demand is mapped, it is important to note that this additional information will not enable Users to replicate the demand data used in the DCLF model exactly. This is due to the treatment of Large embedded generation and station demand, which is not included in these figures.
For the purpose of illustrating system performance, the need or otherwise for transmission reinforcement and for describing opportunities, it is useful to divide the system up and consider power transfers across certain critical boundaries. 17 such boundaries are used in this Statement (11 for England & Wales and 6 for Scotland).
The 17 boundaries are shown schematically/electrically in Figure A.2.3 for SHETL, Figure A.3.3 for SPT and Figure A.4.3 for NGET against the backdrop of the 2012/13 system and are listed in Table 6.3. The 17 boundaries are also shown in Figure A.1.6 against a geographic backdrop, which includes the 2006/07 system. These boundaries are used, amongst other things, to provide a clearer picture of the overall capability of the transmission system to transmit power Transmission System Capability.
The areas of the system described by and/or encompassed by the 17 SYS boundaries are referred to as the SYS Study Zones. There are 17 such SYS Study Zones and these are listed in Table 6.4 and shown in Figure A.1.6 against a geographic backdrop, which also depicts the 2006/07 system.
By the end of 2006/07 the power system in Great Britain will be made up of 159 Large power stations, the 400kV and 275kV transmission system (and 132kV transmission system in Scotland) and 14 distribution systems.
The location of Large power stations is shown against a backdrop of the 2006/07 transmission system in Figure A.1.1 . The existing GB transmission system is again depicted in Figure A.1.2, with the 400kV system shown in blue, the 275kV system in red and the 132kV system in black.
The GB transmission system includes:
Circuit kilometres of overhead lines which are normally energised and in service:
400kV 11,426km
275kV 5,965km
132kV & below 4,799km
Total 22,190km
Circuit kilometres of underground cable which are normally energised and in service:
400kV 166km
275kV 470km
132kV & below 177km
DC (Channel Link) 327km
Total 1,140km
Transmission system facilities where voltage transformation or switching takes place:
400kV 158
275kV 177
132kV & below 240
Total 575
Power transformers and QBs which are normally energised and in service:
Note: 132kV was assumed to be LV in England & Wales, but not in Scotland.
400/275kV 110
400/132kV 9 (SPT only)
275/132kV 38 (SHETL & SPT only)
400/LV 222 (NGET only and includes 400/132kV units)
275/LV 320
132/LV 251
QBs 16
Total 966
Points where electrical supplies are provided to Users:
Note: 132kV & 66kV were assumed to be Supply Voltages in England & Wales, but not in Scotland.
132kV 149
66kV 20
33kV and below 235
Total 404
The majority of Large power stations are directly connected to the GB transmission system. However, several Large power stations are embedded within the lower voltage distribution networks. Medium and Small power stations are currently all embedded within the distribution networks. Table 6.1 summarises the capacity of Large power stations by fuel type and quantity as at the winter peak of 2006/07. The capacity of Auxiliary Gas Turbines associated with the Large power stations are included.
Currently there are two HVDC External Interconnections linking the GB transmission system with External Systems. These are:
Grid Supply transformers connect the GB transmission system with the distribution systems at 'Grid Supply Points', where bulk supplies of electricity are delivered to the Distribution Companies and Non‑Embedded Customers. Electricity is then usually supplied to domestic, commercial and industrial customers through the distribution systems.
Until the 1930's electricity supply in Great Britain was the responsibility of a multiplicity of private and municipally owned utilities, each operating largely in isolation. The Electricity Supply Act (1926) recognised that this was a wasteful duplication of resources. In particular, each authority had to install enough generating plant to cover the breakdown and maintenance of its generation. Once installed, it was necessary to run more plant than the expected demand to allow for possible sudden plant failure.
By interconnecting separate utilities with the high voltage transmission system, it is possible to pool both generation and demand, not only providing a number of economic and other benefits, including:
Three factors can limit the capability of the transmission system to transfer power across a system boundary
The flow of power across the transmission system causes power losses in the various elements of the system. Most of these power losses are a function of the square of the current flowing through the circuit or transformer windings (I2R) and cause unwanted but inevitable heating of transmission lines, cables and transformers. Since such losses are variable they are often referred to as the 'variable' power losses.
In addition there are unavoidable 'fixed' losses associated with overhead lines and transformers. The term 'fixed' losses, however, is something of a misnomer. Relative to the 'variable' losses they are reasonably static, but they can and do vary. 'Fixed' losses on overhead transmission lines take the form of corona losses that are a function of voltage levels and weather conditions. Corona loss is the loss of power to the air and insulation surrounding high-voltage equipment and is generally visible in the dark as a luminous glow surrounding high-voltage conductors.
'Fixed' losses in a transformer take the form of iron losses. Iron losses occur in the iron core of the transformer when subjected to an alternating magnetic field and as such vary with the frequency of the power flow producing the alternating magnetic field. Iron losses are further sub divided into hysteresis and eddy current losses. It may be noted that the 'variable' transformer heating losses mentioned above are sometimes referred to as 'copper' losses in recognition of the material used for transformer windings. Thus transformers have 'variable' copper losses and 'fixed' iron losses.
An estimated breakdown of transmission power losses at the time of ACS peak demand is given in Power Losses.
Users can directly influence the need for major transmission reinforcements by their choice of where to site their new generating stations. For example, if a User sites a new station in an exporting area (i.e. where the amount of generation already exceeds the demand), the maximum power flow will increase and may exceed the firm transmission capacity of the existing system, thus precipitating the need for transmission reinforcement. The converse is, of course, also true.
GB Transmission System described the existing and planned transmission network in terms of its components and structure. This chapter describes the performance of the existing and planned transmission network in terms of:
(i) circuit capacities;
(ii) system power flows;
(iii) grid supply point loadings;
(iv) short circuit currents (single phase and three phase); and
(v) system and zonal power losses.
The reader is reminded that, as explained in Scope on the GB transmission system, the 'SYS background' does not necessarily contain all transmission reinforcement schemes which may in the event be required for compliance with the Licence Standard. GB Transmission System Capability identifies only those reinforcement schemes judged to be necessary to ensure that the transmission system is compliant for the SYS background (see Table 8.2 ). Additional reinforcements to those in Table 8.2 may in the event also be required.
It is useful at this point to explain, in simple terms, the difference between circuit capacity, loading and boundary capability.
The capacity or rating of a circuit is the maximum loading which may be permitted to flow on that circuit under specific conditions (e.g. ambient/seasonal temperature).
The loading on a circuit is the actual or forecast power flow on that circuit resulting from a given set of conditions (e.g. the demand level and the generating plant used in meeting the demand).
The capability of a boundary is the maximum transfer across the boundary that can be tolerated for the particular background of demand and generation under consideration without breaching security criteria. This means that following 'secured events' such as fault outages of transmission circuits, there are, inter alia, no overloaded items of transmission equipment or unacceptable voltages, and all demand is supplied (save as permitted by specific demand connection criteria). The precise criteria are defined in Licence Standard, which is more fully referred to as the GB Security and Quality of Supply Standard (GB SQSS). Compliance with the standard is a condition of the Transmission Licence.
Circuit capacities and loadings are reported in this chapter. Boundary capabilities are reported in GB Transmission System Capability.
Again, as with the previous chapter, many of the figures discussed in this chapter have been included in the Figures and only referenced in the text.
Table B.2.1a for SHETL, Table B.2.1b for SPT and Table B.2.1c for NGET show, inter alia, the post fault continuous ratings (in MVA) of all the circuits of the main interconnected GB transmission system for each season of the year.
The power flows presented in this chapter are based on the SYS background and the Planned Transfer Condition.
The SYS background includes:
(a) the customer based forecast unrestricted ACS Peak GB Demand (less Power Station demand) on the GB transmission System, which is given in Table 2.1;
(b) generation selected from a ranking order based on the existing and proposed new generation for which an appropriate Bilateral Agreement is in place. This generation is presented and discussed in Chapter 3. The techniques for selecting which generation is used to meet the demand are described below; and
(c) the existing transmission network and those planned future transmission developments which have been technically and financially sanctioned by the relevant Transmission Licensee. This is described in Chapter 6.
The demand forecasts used in the power flow analyses include transmission losses ACS Peak GB Demand . For the purpose of illustrating the general power flows throughout the system, these losses are effectively apportioned uniformly across Grid Supply Points through the application of the correction factor described in Customer Demand Data. However, where greater accuracy is required for determining the need for local transmission reinforcements, we would more accurately calculate the losses particular to that local zone.
For illustrative purposes, a useful reference system condition on which to base studies is the Planned Transfer Condition. The Planned Transfer Condition is defined in the Licence Standard. The following paragraphs outline how the techniques for modelling the Planned Transfer, which are set out in the Licence Standard, have been applied for the purposes of this Statement.
Appendix C of the Licence Standard sets out how the Planned Transfer Condition should be modelled. For this purpose, two techniques are described, namely: the Ranking Order Technique (to be applied when the plant margin exceeds 20%); and the Straight Scaling Technique (to be applied when the plant margin is 20% or less).
It should be noted, however, that the License Standard definition of Plant Margin differed from the definition given in Chapter 5, which is used for the more general purposes of this Statement.
The Licence Standard (i.e. the GB Transmission System "Security and Quality of Supply Standard") definition of Plant Margin is:
"The amount by which the total installed capacity of directly connected Power Stations and embedded Large Power Stations exceeds the net amount of the ACS Peak Demand minus the total imports from External Systems. This is often expressed as a percentage (e.g. 20%) or as a decimal fraction (e.g. 0.2) of the net amount of the ACS Peak Demand minus the total imports from External Systems".
The basic difference between the two definitions lies in the fact that, the Licence Standard definition treats imports as negative demand but the SYS definition, used in Chapter 5, treats imports as generation. Whilst the Plant Margin in MW terms remains the same, in percentage terms the SYS margins are lower than would be the case using the Licence Standard definition. Please note that, whilst the wording of the SYS definition of Plant Margin does not mention exports to External Systems, it is implicit that such exports should be treated as positive demand.
The overall process for modelling the planned transfer may be regarded as being made up of the following three parts, the first two of which concern the ranking order technique and the third is obviously concerned with the straight scaling technique. The three parts are:
Ranking Plant in Order of Likelihood of Operation at Peak
This part of the process can be further subdivided into:
Ordering:
A list is compiled of all relevant generating units in the "SYS Background". The term Transmission Entry Capacity (TEC) is defined and used solely on a power station basis and does not exist on a generating unit basis. In view of this, each unit on the list is attributed with the appropriate Registered Capacity (RC) and each power station is attributed with the appropriate TEC, correct as at the "data freeze date".
All generating units are then arranged in order of their perceived likelihood of operation at the time of the ACS Peak GB Demand. For existing generation, this is achieved by inspection of the unit operation experienced over the previous winter period, which is taken as being from the beginning of December to the end of January. In general, if the unit operated at the daily peak it is attribute a score of "1" whether operated at full or part load. If the unit did not operate it is attributed a score of "0". Scores for each unit are then aggregated to give the "probability of running" for each unit. A high probability of running would mean that the relevant unit is ranked as having a high likelihood of operation over the coming winter peaks and vice versa.
Future plant is ranked according to plant type. Future plant is likely to achieve a relatively high ranking given that it likely to be modern and efficient unless the particular plant is designed to operate at base load only. However this is a general rule and, rather than strict adherence, the rule is applied in a pragmatic way. That is, the results of its application are tempered by judgement based market intelligence. Accordingly, a particular plant with a low score may be moved up the ranking if market intelligence suggests this to be the more likely outcome or vice versa.
Limiting Aggregate Unit Output to Station TEC:
Ordering the generating units, as described above, may result in generating units at the same power station being placed in widely differing positions in the ranking order. The aggregate of the unit RCs at each power station is then limited to the station TEC. This is achieved by progressively accumulating the unit RC of each station in the ranking order and comparing the aggregate with the relevant station TEC. If and when the cumulative RC equals or exceeds station TEC, then the RC of subsequent, as yet unselected, units at that station are set to zero. This goes some way towards emulating whole set modelling. In cases where the aggregate of the unit RC at a station needs to be reduced by less than a whole set, that reduction is spread proportionately across all selected units at the station (i.e. units higher in the ranking order) unless a reduction in a GT unit can accommodate the difference between aggregated RC and TEC. At this point in the process, all plant has an assumed 100% availability.
The resultant ranking order of generation operation, with each power station output limited to the appropriate TEC, is given in Table 7.1.
As a point of interest, Figure 7.1(a ), Figure 7.1(b ), Figure 7.1(c ) and Figure 7.1(d ) indicate how generation was actually used to meet demand on each of the four days referred to in Figure 2.2 of Chapter 2. These are the winter maximum (29/11/05), typical winter (15/12/05), typical summer (15/06/05) and summer minimum (03/07/05) respectively.
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The same information is given in pie chart form in Figure 7.2(a ), Figure 7.2(b ), Figure 7.2(c ) and Figure 7.2(d).
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Identification of Contributory and Non - Contributory Plant
This part of the process is concerned with identifying that generating plant which is most likely to operate at the time of system peak in a climate where plant margins exceed 20%.
For analysing the performance of the transmission system at the time of winter peak, the load factor over the winter peak period becomes relevant. Experience shows that this is in the region of 90% and 36% for conventional and wind based generation respectively. These figures translate into assumed winter peak availabilities of 100% and 40% for conventional and wind based generation capacity respectively.
Accordingly, in establishing which plant, in the ranking order of Table 7.1, is to be regarded in this Statement as contributory and which is to be regarded non-contributory, the cumulative system generation capacity to be compared with demand in the calculation of plant margin has been taken as 100% of the capacity of each conventional generator and 40% of that of each wind farm.
The lower ranking plant in the ranking order is then progressively removed and treated as non-contributory, until a Plant Margin of just 20% is achieved. It is worth reiterating that the Plant Margin referred to is as defined for the purpose of the Licence Standard.
The result of the above ranking order technique, which is used only if the plant margin exceeds 20%, is a list of contributory plant, with unit outputs, which sum to equal 120% of (unrestricted "ACS Peak GB Demand" less Station Demand). The full capacities of all the contributory generation is used as the initial basis for system studies.
Application of the Straight Scaling Technique
The straight scaling technique is applied when the plant margin, as defined in the Licence Standard, is equal to or less than (although still positive) 20%. Accordingly, the straight scaling technique is applied following application of the ranking order technique or otherwise straight away when the plant margin is already 20% or less.
The straight scaling technique, which is set out in the Licence Standard, involves the application of scaling factors 'A' and 'S'. The 'A factors' relate to the expected availability of each generating plant type at the time of the peak. The 'S factors' relate ratio between the system demand to be met and the total generation capacity available. Under the technique, the generation output, for study purposes, of all contributory plant is calculated for the 'planned transfer condition' by applying 'A' and 'S' scaling factors to their capacities such that the aggregate effective generation of all contributory plant is equal to the forecast peak demand plus transmission losses less imports from external systems.
In recognition of their different characteristics and use, specific values of the 'A factors', which relate to expected generating plant availability, defined in the Licence Standard may be used for thermal, hydro and wind generation. The values are chosen in order that the 'required transfer capability' , which is simply the sum of the 'planned transfer' and the appropriate 'interconnection allowance', will represent approximately the same percentile of the actual distribution of power transfers at time of peak demand whether the background includes wind or hydro generation or not. In the power system analyses, which underlie the power flows and capabilities presented in this Statement, the following values were used: 100% for thermal; 100% for hydro; and 72% for wind.
Imports from External Systems are not subject to scaling. According to the Licence Standard definition of Plant Margin, Imports from External Systems are deducted from the demand to be met and Exports to External Systems form part of the demand to be met.
Power flows on the SHETL network for each of the seven years from 2006/07 to 2012/13 are illustrated in the following series of figures: Figure C.1.1 ; Figure C.1.2 ; Figure C.1.3 ; Figure C.1.4 ; Figure C.1.5 ; Figure C.1.6 ; and Figure C.1.7.
Power flows on the SPT network for each of the seven years from 2006/07 to 2012/13 are illustrated in the following series of figures: Figure C.2.1 ; Figure C.2.2 ; Figure C.2.3 ; Figure C.2.4 ; Figure C.2.5 ; Figure C.2.6 and Figure C.2.7.
Power flows on the NGET network for each of the seven years from 2006/07 to 2012/13 are illustrated in the following series of figures: C.3.1; Figure C.3.2 ; Figure C.3.3 ; Figure C.3.4 ; Figure C.3.5 ; Figure C.3.6 and Figure C.3.7.
While the complex power flow program used computes nodal voltage, phase angles and both real and reactive power flows on the system only the real (MW) power flows have been displayed on the figures, both for ease of presentation and for clarity.
The requirements placed on the transmission system depend on the size and geographical/ system location of generation and demand.
SYS Boundaries and SYS Study Zones introduced the 17 SYS boundaries which are used for the purpose of illustrating system performance, illustrating the need or otherwise for transmission system reinforcement and for describing opportunities. These boundaries encompass the 17 SYS Study Zones.
Table 7.2 and Table 7.3 summarise the Planned Transfers, under the SYS background, for each of the 17 SYS Study Zones and across each of the 17 SYS boundaries respectively. Please note that, the generation capacities used and, accordingly, the resultant level of planned transfer, relate to the expected contributory generation plant rather than the installed capacity. This is in line with the power flows illustrated by the series of figures in Appendix C.
In general terms, the disposition of demand and generation across the GB transmission system is such that much of the generation capacity is located in or towards the northern parts of the system while much of the demand is located in the southern parts of the system. As a consequence, the resultant power broadly flows from the northern parts to the southern parts of the system, particularly at times of the GB system peak.
The capacity of transmission contracted generation is set to rise by some 18.2GW over the period 2006/07 to 2012/13 (Table 3.5 refers). Amongst other things, Generation Disposition described the disposition of this future plant. In broad terms 5GW will be located in Scotland, 1.7GW in the north of England and the midlands with the remaining 11.5GW south of the midlands to south boundary. However, these figures do not include the prospective growth of embedded generation; particularly in wind farms. This receives some consideration in Embedded and Renewable Generation.
The year on year fluctuations in planned transfer, displayed in Table 7.2 and Table 7.3, are not only a function of changes in demand and installed generation disposition, but also of the changing contributory plant disposition. Generation Disposition reports that, the forecast disposition of contributory generation and ACS demand across the system is such that, against the SYS background, the high power transfers at times of peak demand from the, northern parts of the system to the southern parts, are expected to persist.
Under the 'SYS background' the export from Scotland into England (i.e. across Boundary 6) displays a more or less steady increase over the period. Most 'North to South' boundaries display a similar trend, which is partly a product of the northern location of much of contracted renewable energy developments. Small perturbations reflect the changing 'in merit' generating plant.
The import into the Southwest Peninsula is reduced over the period due to new generation scheduled to connect in that part of the network while the demand in London displays a steady growth resulting in a gradual increased London import over the period.
Figure 7.3 and Figure 7.4 illustrate the broad power flow pattern for 2006/07 and 2012/13 respectively. The capability of the GB transmission system to transport these levels of power transfer across system boundaries is the subject of Transmission System Capability. Amongst other things, that chapter explains that in considering boundary transfers and capabilities and the possible need for additional reinforcement it is important to take account of the requirements of the planning criteria in the Licence Standard. In particular, planning criteria relating to the main interconnected transmission system require that a margin for security (i.e. the interconnection allowance) should be allowed for.
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The outturn power flows at the peak of any year may differ from those given in Table 7.2 , Table 7.3, Figure 7.3 , Figure 7.4, and the series of figures included in Appendix C for a number of reasons. These include:
There are clearly a great many variables, which will influence the outturn power flow. However, whilst the power flows displayed in the various tables and figures of this chapter may not be experienced in practice, they are nevertheless indicative of the flows to be expected under the SYS background. Power flows, transmission capabilities and the possible need for further transmission reinforcement based on our current view of a more likely outturn than the SYS background are discussed in GB Transmission System Capability.
At off-peak times less generation capacity is needed to meet the reduced demand and only the higher plant in the ranking order is used within the limits of system constraints. Thus the power flows around the system and circuit loadings not only change as a result of the lower demand levels but also because of the changes in the contributory generation disposition.
Transmission circuit thermal ratings reduce outside the winter period and, in addition, the system may become depleted due to transmission circuits and generation units being taken out of service for planned maintenance and other reasons. Maintenance practices on our system generally results in a boundary made up of about eight circuits being continuously depleted by one or other of its circuits between the months of April and October.
The net result is that both circuit loadings and boundary capabilities will vary at off-peak times according to prevailing conditions. They may be either higher or lower relative to the peak period. In view of the many variables associated with the real-time operation of the system, it is not a worthwhile exercise to present a rigorous analysis of possible future off-peak power flows and capabilities in this Statement.
In the real time phase of operation the system is managed such that it complies with the operational criteria in our Licence Standard. In applying this standard, which is aimed at ensuring the required level of security and quality of supply, prevailing conditions are taken into account. Power transfers around the system are managed such that, amongst other things, circuit loadings would remain within their rating and boundary transfers within their capability and no unacceptable conditions will arise even with specified circuit fault outages on top of any maintenance outages.
It was explained in Demand on the Grid Supply Points that Grid Supply Points (GSPs) are the points of connection between the GB transmission system, distribution networks, Large power stations and other Non-Embedded Customers where we deliver electricity.
The loading on a GSP is the demand on the lower voltage (LV) side less the output of any Large power station connected to the LV side or embedded within the distribution system fed from that point. An allowance for the output from embedded Medium and Small power stations is already included in the users' demand estimates as explained in Customer Demand Data.
For the SYS background, the GSP net loading is the difference in flows into and out of that GSP. Such power flows are shown in the series of power flow figures included in Appendix C. This GSP loading is net of any generation at that point. A more direct and detailed indication of GSP loading at maximum demand is given in the series of tables: Table 2.2a ; Table 2.2b ; Table 2.2c ; Table 2.2d ; Table 2.2e ; Table 2.2f ; and Table 2.2g.
It was also explained in Customer Demand Data that, for infrastructure planning, the demand at time of our system peak is used. These forecasts of demand at the time of system peak underlie the customer based demand forecast of Table 2.1 and the series of power flow figures included in Appendix C. For GSP planning, the demand at the GSP peak is more appropriate. This demand is used, together with appropriate allowances for embedded Large power stations, in the application of the criteria for design of demand connections in the Licence Standard.
Engineering Recommendation G74 defines a computer based method for the calculation of short circuit currents and has been registered under the Restrictive Trade Practices Act (1976) by the Energy Networks Association (ENA), formerly the Electricity Association, and the associated Statutory Instrument has been signed to this effect.
Three phase to earth and single phase to earth short circuit current analyses have been conducted by each Transmission Licensee (SHETL, SPT and NGET), in respect of their own Transmission Areas, in accordance with ER G74. The series of tables, Tables D.1 to D.12, which are included in Appendix D, list the results of these analyses. To assist the reader in understanding the results, the next section of this chapter explains some of the salient points relating to the short circuit calculations including assumptions made and terminology used.
Tables B.6a to B.6c list the types of circuit breakers currently found at SHETL, SPT and NGET substations respectively together with their ratings (the NGET ratings are given for 400kV and 275kV voltage levels only). From this list it can be seen that several substations have a mixture of circuit breakers installed and this results in a range of ratings for those substations. Generally the substation infrastructure will have a similar rating to the associated circuit breaker.
The listed ratings should be regarded as indicative and therefore used as a general guide only. Should a customer require more detailed information relating to a specific site he may contact us as described in Further Information.
Furthermore, although the short circuit duties at a node may at times exceed the rating of the installed switchgear, the switchgear may still not be overstressed for one or more of the following reasons:
Finally, please also note that, as explained in Network Parameters, substation running arrangements are subject to variation. The running arrangements used for determining the short circuit currents presented in Tables D.1 to D.12 may, in some cases, differ slightly from those presented elsewhere in this Statement.
International Standard IEC909, "Short-Circuit Current Calculation In Three Phase AC Systems" was issued in 1988 and has subsequently been published as British Standard BS7639. When IEC909 was issued the Electricity Supply Industry had no standard method or uniform methodology for fault level calculation. The hand calculation methodology detailed in IEC909 was considered conservative for the UK supply system and it was believed that its application could lead to excessive investment. In consideration of this potential excessive investment, an industry wide working group was established in 1990 to define "good industry practice" for the calculation of short circuit currents.
The resulting document, Engineering Recommendation G74 (ER G74), defines a computer based method for calculation of short circuit currents which is more accurate than the methodology detailed in IEC909 and, as a consequence, potential capital investment is more accurately identified. As previously mentioned, ER G74 has been registered under the Restrictive Trade Practices Act (1976) by the ENA and the associated Statutory Instrument has been signed to this effect.
Sophisticated computer programs are used for the purpose of conducting short circuit current analyses. Each analysis is based on an initial condition from an AC load flow and is carried out in accordance with ER G74. The broad calculation methodology is summarised in the following paragraphs.
When assessing the duties associated with busbars, bus section/coupler circuit breakers and elements of mesh infrastructure, it is assumed that all connected circuits contribute to the fault. When assessing the duties associated with individual feeder/transformer circuits it is assumed that the fault occurs on the circuit side of the circuit breaker with the remote ends of the circuit open. These represent the most onerous conditions.
Short-circuit currents are calculated using a full representation of the GB transmission network. Directly connected and Large embedded generating units are also discretely represented with their electrical parameters based on data provided by the owner of the generating unit. Other Network Operators' networks are represented by network equivalents at the interface between the GB transmission system and the Network Operator's network. For example, a DNO network connected to a 132kV busbar supplied by SGTs will usually be represented by a single network equivalent in the positive phase sequence (PPS) and zero phase sequence (ZPS) networks. The use of network equivalents allows short-circuit currents in the GB transmission system to be calculated with acceptable accuracy and provides a good indication of the magnitude of the short-circuit currents at interface substations. Short-circuit currents quoted in Tables D.1 to D.12 for interface substations are not, however, suitable for specifying short-circuit requirements for new switchgear at the interface substations. These will need to be agreed between the relevant Transmission Licensee and the Network Operator on a site specific basis.
The short circuit current is made up of an AC component with a relatively slow decay rate as shown in Figure 7.5 and a DC component with a faster decay rate as shown in Figure 7.6 . These combine into the waveform shown in Figure 7.7 . The waveform in Figure 7.7 represents worst case asymmetry and as such will be infrequently realised in practice.
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X/R Ratio
The DC component decays exponentially according to a time constant which is a function of the X/R ratio. This is the ratio of reactances to resistances in the current paths feeding the fault. High X/R ratios mean that the DC component decays more slowly.
DC Component
The DC component of the peak make and peak break short-circuit currents are calculated from two equivalent system X/R ratios. An initial X/R ratio is used to calculate the peak make current, and a break X/R ratio is used to calculate the peak break current. Calculation of the initial and break X/R ratios is undertaken in accordance with IEC 60909-0 (2001-07) Method C (also known as the equivalent frequency method). We consider the equivalent frequency method to be the most appropriate general purpose method for calculating DC short-circuit currents in the GB transmission network.
The DC component of short-circuit current is calculated on the basis that full asymmetry occurs on the faulted phase for a single phase to earth fault or on one of the phases for a three phase to earth fault.
Making Duties
The making duty on bus section/bus coupler breakers is that imposed when they are used to energise an unselected section of busbar which is either faulted or earthed for maintenance. Substation infrastructure such as busbars, supporting structures, flexible connections, conductors, current transformers, wall bushings and disconnectors must also be capable of withstanding this duty.
The making duty on individual circuits is that imposed when they are used to energise a circuit which is either faulted or earthed for maintenance. This encompasses the persistent fault condition associated with Delayed Auto-Reclose (DAR) operation.
Breaking Duties
Bus section/coupler breakers are required to break the fault current associated with infeeds from all connected circuits if a fault occurs on an uncommitted section of busbar. Circuit breakers associated with a feeder/transformer or a mesh corner are required to break the fault current on the basis that the circuit breaker is the last circuit breaker to open clearing the fault.
Circuit breakers associated with faulted circuits are required to interrupt fault current in order to safeguard system stability, prevent damage to plant and maintain security and quality of supply.
Initial Peak Current
In Figure 7.7, both the AC and DC components are decaying and the first peak will be the largest and occurs at about 10ms after the fault occurrence. This is the short circuit current that circuit breakers must be able to close onto in the event that they are used to energise a fault, hence this duty is known as the Peak Make. However, this name is slightly misleading because this peak also occurs during spontaneous faults. All equipment in the fault current path will be subjected to the Peak Make duty during faults and should therefore be rated to withstand this current. The Peak Make duty is an instantaneous value.
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RMS Break Current
This is the RMS value of the AC component of the short circuit current at the time the circuit breaker contacts separate (see Figure 7.5), and does not include the effect of the DC component of the short circuit current.
DC Break Current
This is the value of the DC component of the short-circuit current at the time the circuit breaker contacts separate (see Figure 7.6).
Peak Break
As both the AC and DC components are decaying, the first peak after contact separation will be the largest during the arcing period. This is the highest instantaneous short circuit current that the circuit breaker has to extinguish, hence this duty is known as the Peak Break. This duty will be considerably higher than the RMS Break because, like the Peak Make duty, it is an instantaneous value (therefore multiplied by the square-root of 2) and also includes the DC component.
Choice of Break Time
The RMS Break and Peak Break will of course be dependent on the break time. The slower the protection, the later the break time and the more the AC and DC components will have decayed. For the purposes of this Statement a uniform break time of 50ms has been applied at all sites. For the majority of our circuit breakers, this is a fair or pessimistic assumption. In this context it should be noted that the break time of 50ms is the time to the first major peak in the arcing period, rather than the time to arc extinction.
Generator Infeed Data
All generating units of directly connected Large power stations are individually modelled together with the associated generator transformers. Units are represented in terms of their Positive Phase Sequence (PPS) sub transient and transient reactances (submitted under the provision of Grid Code), as well as the DC stator resistances and Negative Phase Sequence (NPS) reactances (neither of these data items are submitted under the Grid Code but the stator resistance value is currently derived or assumed from historic records and the NPS reactance is calculated as the average of the relevant PPS sub transient reactances ((Xd" + Xq")/2). Fault level studies for planning purposes are carried out under maximum plant conditions (i.e. with all Large power stations included whether contributory or not) to simulate the most onerous possible scenario for a future generation pattern.
Auxiliary System Infeed Data
The induction motor fault infeed from the station board is modelled at the busbar associated with the station transformer connection. Where sufficient information is not available, it has been assumed that Auxiliary Gas Turbines are connected to the station boards as well as to the main generating units in order to simulate the most onerous condition. Where the X/R Ratio has not been provided, a value of 10 has been assumed.
Where the information is available, the fault infeed from the unit board, due to induction motors and auxiliary gas turbines, is modelled as an adjustment to the main genset substransient reactance. A more detailed model of the power station system may have to be used to assess fault levels when station and unit boards are interconnected.
GSP Infeed Data
Infeed data for induction motors and synchronous machines at GSPs is submitted by Users under the provision of the Grid Code. Infeeds from induction motors and synchronous machines are modelled as equivalent lumped impedances at the GSP.
Where the information is not available, 1MVA of fault infeed per MVA of substation demand, with an X/R ratio of 2.76 is assumed for all induction motors in the absence of more detailed data. This is in line with the requirements of ER G74.
Where more detailed fault level studies are required at 132kV or below, the associated system should be modelled in detail down to individual Bulk Supply Points (BSP's). Induction motor infeeds should then be modelled at these BSP busbars.
LV System Modelling
Where interconnections exist between GSP's, these equivalents take the form of PPS impedances between those GSP's. The ZPS networks take the form of minimum ZPS values modelled as shunts at the GSP busbars.
Where interconnections to other GSP's do not exist, the equivalents take the form of equivalent LV susceptances modelled as shunts at the GSP busbar. The ZPS networks are modelled as shunt minimum ZPS values at the GSP busbars.
The values of PPS impedances between GSP's shunt LV susceptances and shunt ZPS minimum impedances are as submitted by the Users under the provision of the Grid Code.
The following information on system power losses and zonal power losses is indicative only and is included to provide an insight into the level and type of power loss which may be expected around the system at the time of system ACS peak and against the SYS background only. At other times and/or against other backgrounds different levels of power loss may arise.
An estimate of the level of system power loss occurring at the time of the ACS Peak GB Demand for the years 2006/07 to 2012/13 against the SYS background is given in Table 7.4. The losses shown are those incurred on the system between the power station generating unit and the grid supply points and are made up of:
It is stressed that the losses shown in Table 7.4 are indicative only. They correspond to the time of ACS Peak Demand and have been evaluated against the 'SYS background'. The 'fixed' losses, like the 'variable' losses, can also vary to a certain extent. Accordingly, the exact losses on the day can vary for a number of reasons including:
Total system power losses are shown in line 5 of Table 7.4 and these have also been expressed as a percentage (line 7) of the forecast ACS peak demand stream given in Table 2.1 less station demand and less transmission losses (line 6). The demand forecast given in Table 2.1 reflects the demand seen at the metering points at the power stations and accordingly includes both transmission and distribution system losses. As some metering is on the high voltage side of the generator transformers and some on the low voltage side, generator transformer copper losses are only partially taken into account.
The transmission heating losses (line 1) are a function of the power flow pattern around the system and the reduction in 2010/11 is due to the commissioning of new plant in the south which 'backs off' the north to south flows.
Fixed losses (line 2) are fairly constant over the period. Grid Supply transformer heating losses (line 3) display a modest increase over the period in step with the growth in forecast ACS Peak Demand (line 6). Generator Transformers heating losses (line 4) display a modest decrease over the period.
Less significant perturbations, perhaps not obvious in the results displayed in the table, are caused by a number of factors including: increased transmission capacity (through reinforcement rather than reprofiling) which reduces transmission heating losses; or embedded Large power stations closing, decommissioning or otherwise becoming non-contributory which can increase grid supply transformer heating losses.
Relative to the system power losses reported in the 2005 GB SYS, there is a small decrease in total losses. This is also reflected in the corresponding reduction in transmission heating losses, which are the dominant component of system power losses. This reduction is due, in part, to a relative increase in the number of transmission reinforcements included in the SYS background.
Amongst other things, the commissioning and operation of a new power station will have an effect on transmission losses and this will be a function of its system location and the prevailing power flows at the time.
Clearly, if a new power station were to be located in the north, and this were to displace the operation of southern generation, then the north to south power flows would increase, transmission losses would increase and some of the output of the new station would, in effect, be 'lost' to the system. However, if the new power station were to be located in the south and this displaced northern generation, the converse would be true; north to south power flows would decrease, system losses would decrease and the relative net effect would be as if a larger station had been installed. Table 7.5 demonstrates this by showing the relative effect on transmission losses of locating 100MW of new generating plant in each zone consecutively. For this purpose, the 17 SYS Study Zones introduced in SYS Boundaries and SYS Study Zones have been used.
Please note, however, that the power flows presented in this Statement are based around a winter peak demand case using an average plant availability which tends to give rise to a general north to south power transfer. At other times of the year, when plant availability and market conditions may modify the generation patterns, zonal losses can change dramatically. For example, if Scotland becomes an importing area during the summer period then siting generation in Scotland is likely to have a beneficial effect on GB transmission losses.
The analysis was carried out against the SYS background for the 2012/13 winter peak. The installation of new generation was represented by a 100MW reduction in demand spread across the nodes within the relevant zone. The computer program used in the analysis requires that the total generation matches total demand (including losses) and scales generation capacity accordingly. The studies were arranged such that the effective 100MW of new generation was compensated for by a slight reduction in the output of all other generation in the study. That is no plant was displaced from operating. This was repeated for each of the 17 zones and the change in losses, relative to a reference case where no 100MW of new generation was introduced, was calculated.
Table 7.5 lists the resultant generation effectiveness in percent for each SYS Study Zone. For example, an effectiveness of 92% means that for a small increase in generation, 92% will meet demand, whilst 8% will be accounted for by increased losses.
Table 7.5 shows that a small increase in generation in the zones north of zone 5 has an effectiveness of 90% or less in meeting demand across the system at the time of winter peak. In contrast to this, a small increase in generation in the South West (zone 17) has an effectiveness of 110% in meeting demand by virtue of reducing transmission power losses. Whilst these results are very broad brush and absolute percentages should not be relied upon, the relative order is considered reasonably robust. Please note that the generation effectiveness in zones 1 to 6 is likely to be understated due to the non-compliance of Boundary 6.
Finally, whilst the results may hold for the addition of 100MW of new generation, it does not follow that they would hold for say 1000MW of new generation. The aim of the above exercise was to provide an insight into the general effect of generation location on the overall GB transmission losses. The capacity of 100MW of new generation was selected as, in itself, it has a relatively small system impact. The choice of a larger capacity (say 1000MW) would be more likely to incur heavy local loading of transmission circuits creating increased local transmission losses. Depending on the location, this may increase or decrease the overall GB system losses. It is also more likely that a generator of this size would require network reinforcement to ensure compliance with the Licence Standard. Consequently, it would not be appropriate to calculate zonal losses until that reinforcement had been included in the study. The effect of a smaller generator capacity (say 1MW) would not be seen.
This chapter describes the capability of the GB transmission system to transport power at the time of the system ACS peak. The power system analyses underlying many of the results discussed in this chapter have been conducted on the basis of the deterministic SYS background. The deterministic SYS background comprises the customer based demand forecasts of Electricity Demand , the existing and future transmission contracted generation of Generation and the existing and planned transmission network described in GB Transmission System. It should be noted that calculated system capabilities are a function of the generation, demand and transmission background against which they are assessed. Accordingly, the computed capabilities reported in this chapter are those which would arise should the SYS background be realised at the time of system peak. At other times and/or against other backgrounds different transmission capabilities may arise.
As explained in previous chapters, there is uncertainty associated with the demand forecasts and with future generation developments. Thus, it should be recognised that the SYS background does not necessarily represent the most likely outcome, nor should it be regarded as a 'forecast' of the outcome. Uncertainties in demand and generation developments will affect future power transfers, transmission system capabilities, the need or otherwise for transmission system reinforcements and the opportunities for making new or further use of the transmission system.
In view of this, the transfers and capabilities arising from the deterministic SYS background have been presented against the backdrop of a range of probabilistic transfers. These probabilistic transfers reflect, in part, our current views on a range of criteria, which influence the likely future outcome given the various generation and demand uncertainties. This presentation is intended to provide a more meaningful view of future transfers, promote a better appreciation of the future uncertainty we face in planning the system and enable the reader to make more informed judgements on the opportunities for making new or further use of the transmission system.
The chapter also identifies those reinforcements which could be required, in addition to the planned reinforcements presented in GB Transmission System, to achieve compliance with the Licence Standard on the basis of the SYS background. These additional reinforcements are subject to variation and should be regarded as indicative only.
The probabilistic range of transfers, included in this chapter, have been derived using a National Grid program called the Generation Uncertainty Model (GUM). To provide a greater understanding of the probabilistic results presented and how they should be interpreted , the chapter includes a high level description of GUM.
An understanding of the capability of the GB transmission system to transport power leads to an understanding of the ability of the GB transmission system to accommodate further generation and demand in different zones across the system. When considering the capability of the system, it is useful to consider the limits on the bulk transfer of power across certain system boundaries.
Accordingly, this chapter reports on a number of key boundary capabilities and, for this purpose, the boundaries described in GB Transmission System and shown in Figure A.2.3 , Figure A.3.3 and Figure A.4.3 have been used. These boundaries are also shown in Figure A.2.3 for SHETL, Figure A.3.3 for SPT and Figure A.4.3 for NGET. These 17 boundaries have historically reflected some of the main weaknesses on the interconnected system. Such weaknesses can lead to the need to restrict power flows across the system; possibly through the potentially uneconomic constrained operation of generating plant. Alternatively, transmission weaknesses may be removed through some form of transmission reinforcement. Although the most critical boundaries may not now be precisely the same as those studied, the 17 boundaries which have been used remain relevant for illustrating system trends and limitations.
Consideration of the range of possible future transfers across each of the 17 boundaries enables us to describe the type of reinforcement schemes, which may be required in order to ensure continued compliance with the Licence Standard.
Two types of system limitation, relating to the transfer of power across a boundary, have been considered. The first relates to thermal capability and the second to voltage capability. The boundary capabilities have been evaluated for the time of the system winter peak demand of 2006/07, 2008/09, 2010/11 and 2012/13 and are on the basis of the SYS background. These capabilities will, of course, potentially change at off-peak times but, as explained in Off-Peak Power Flows, in the 'real time' operational time-phase, the system is managed such that it complies at all times with operational criteria of the Licence Standard.
As mentioned above, the Licence Standard defines certain unacceptable conditions, which shall not occur as a result of specific secured events. The unacceptable conditions referred to include:
For example, in the case of planning the development of the Main Interconnected Transmission System, a boundary in which a single circuit is out of service due to a fault, must be capable of transferring the Planned Transfer (as defined in the Licence Standard) plus an allowance (also specified in the Licence Standard) to take account of non-average conditions (e.g. relating to power station availability, weather and demand) without any of the above unacceptable conditions arising. The allowance, referred to, is calculated by an empirical method described in the Licence Standard and is called the "Interconnection Allowance".
Similarly, the Licence Standard also requires that a boundary, in which two circuits are out of service (i.e. N-2 or N-D as appropriate), must be able to transfer the Planned Transfer plus half the calculated Interconnection Allowance without any unacceptable conditions arising.
Accordingly, the boundary thermal capability is the power flow that can be transferred across the boundary without causing any unacceptable conditions following the outage of two circuits (i.e. N-2 or N-D) as defined in the Licence Standard. The overall boundary capability is the lower of the thermal (MW) and voltage capabilities. Known stability limitations are also reported in the Boundary Commentary section which is presented later in this chapter. The required capability is simply the Planned Transfer plus half the Interconnection Allowance.
Please note, however, that application of the Interconnection Allowance (or part thereof) relates only to those boundaries, which divide the system into two contiguous parts, the smaller of which contains more than 1500MW of demand. In the case of the boundaries, which have been defined for the NGET and SPT systems, this is always the case. However, for a number of boundaries in the SHETL system (namely: boundaries B1, B2 and B3), this is not the case and, in these instances, the required capability is quoted below simply as being equal to the Planned Transfer.
The boundary capabilities reported in this chapter give an indication of the maximum boundary transfer that can be supported without contravening any of the above unacceptable conditions following a secured event. A boundary capability that is less than the required capability indicates a need for transmission reinforcement. A boundary capability that is greater than the required capability shows only that the security criteria are satisfied for the particular transfer conditions and background studied.
The amount by which a boundary capability exceeds the required capability gives an indication of the approximate extent of 'spare' transfer capacity on that boundary. However, this does not necessarily mean that an equivalent volume of additional generation on the exporting side of the boundary (or an equivalent volume of additional demand on the importing side) can be readily accommodated. While not identical (particularly for voltage control and fault levels), in terms of flows on the system, the withdrawal of generation will have a broadly similar effect to the addition of demand and vice versa. This can be due to a number of reasons including:
The nature of a boundary capability can be illustrated by separately establishing the voltage capability and the thermal capability. The way in which voltage or thermal considerations might be the limiting factor in different years is illustrated in Figure 8.1. The voltage capability is shown as a blue line (this may arise either because of unacceptable voltage conditions or insufficient voltage performance margin, whichever limit arises first), and the thermal capability as a green line. The net boundary capability is shown by the red line.
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The power flows presented in this chapter are based on the deterministic SYS background. There is inherent uncertainty associated with the assumptions underlying any deterministic background. For example demand and generation may, in the event, deviate from any of the deterministic assumptions underlying the background. Uncertainty must also therefore be attributed to both the resultant deterministic power flows and any consequent perceived need for transmission reinforcement. The SYS background is no exception and, while it has been selected as the most reasonable deterministic background for the purposes of Chapter 7, it should not be assumed that it represents the most likely future outcome.
For ease of explanation, the boundary commentaries presented later in this chapter include a series of figures (Figure 8.B1 , Figure 8.B2 , Figure 8.B3 , Figure 8.B4 , Figure 8.B5 , Figure 8.B6 , Figure 8.B7 , Figure 8.B8 , Figure 8.B9 , Figure 8.B10 , Figure 8.B11 , Figure 8.B12 , Figure 8.B13 , Figure 8.B14 , Figure 8.B15 , Figure 8.B16 and Figure 8.B17). Amongst other things, each of these figures shows the planned transfer, the required capability and the actual calculated capability for the relevant boundary. These values are all calculated on the basis of the deterministic SYS background and, in view of this, they are often referred to as the "SYS Transfer", the "SYS Required Transfer" and the "SYS Capability" respectively.
As specified by the Licence Standard, for a particular generation and demand background, the required capability is simply the planned transfer enhanced by the appropriate Interconnection Allowance for the boundary in question. Where the required capability is less than the actual boundary capability, there is no need for further reinforcement in respect of that particular boundary. An example of this is given in Figure 8.2, which illustrates that the required capability exceeds the actual capability from around year 3 onwards indicating a potential need for further reinforcement on the basis of the SYS background.
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The boundary capabilities quoted in this chapter relate to planning the medium to long term future development of the system and are not necessarily appropriate to the real time operation of the system. Operational boundary capabilities are a function of the real time transfer, which can be achieved within operational timescales for a given pattern of system outages, demand and generation availability. In operational timescales each of these factors is known with a relatively high degree of certainty, which is unlike in the planning time phase where there is a need to consider a great many more uncertainties.
The boundary capabilities reported in this chapter do, nevertheless, provide a good broad appreciation of the overall capability of the GB transmission system to transport power. An apparent surplus of boundary capability over the required capability generally shows the exporting side to have at least some potential for additional generation and the importing side to have some potential for additional demand. A deficit of boundary capability against the required capability provides an indication that, were the SYS background to be realised, either investment to reinforce the system and thereby enhance the capability may be appropriate, or alternatively constrained operation of generation is required in order to limit the boundary transfers to within acceptable levels.
The possible need, or otherwise, for transmission reinforcement is discussed under Boundary Commentary.
Finally, for the purpose of providing the power flow information reported in this chapter and in Chapter 7, it is first necessary to be able to obtain a converged AC power flow study at least for the intact system and for the Planned Transfer Condition. Under the SYS background there are a number of boundaries for which the boundary capability is substantially lower than the planned transfer in a number of years. In those cases where such deficits are large, convergence of the AC power flow program may be inhibited. It such cases it may be necessary to add a minimum number of indicative system reinforcements solely for the purpose of obtaining convergence of the Planned Transfer Condition. These 'indicative convergence works' (e.g. reactive compensation to achieve acceptable voltage conditions) are not necessarily sufficient for compliance with the Licence Standard, and the boundary capabilities have been quoted with them included.
Deterministically derived boundary transfers are useful but have limited value since they do not consider the uncertainties associated with projected future demand and generation developments. It is important to take account of the potential impact of these uncertainties on power transfers across key transmission boundaries when considering the merits of transmission reinforcements.
For a given set of assumptions relating to demand and generation, the Generation Uncertainty Model (GUM) provides a probabilistic representation of the electricity market. GUM employs a Monte Carlo model in which openings of new generating stations and closures of existing stations are randomly selected (subject to the influence of the input assumptions) against a background of uncertain demand growth. The resultant probabilistic transfers reflect our current view of how the planned transfers across each of the 17 boundaries at the time of system peak are likely to develop over the next seven years.
Factors which have been taken into account in compiling the input data for GUM include but are not limited to the possible:
It is not possible to provide the detail of the input assumptions we have made since this would breach our obligations on commercial confidentiality. The probabilistic transfer information is provided without prejudice and reflects our current view of future uncertainty. Clearly, this view may change as developments in the electricity market in Great Britain unfold, but nevertheless it should prove a useful complement to the simple deterministic SYS background approach.
The purpose of presenting this additional information is to:
For each year within the period of study, GUM models the system at the time of peak demand on the GB transmission system. This is consistent with the deterministic boundary transfer and capability analyses. The program does not simulate the system year-round; its purpose is to model the generating capacity that might be available to meet the likely peak demand.
The input information provided to GUM reflects our current views on the various generation and demand uncertainties. Our market intelligence in this area is largely based on material in the public domain. In compiling the input assumptions we have tried to avoid introducing any bias. Clearly, our views may change as developments in the electricity market in Great Britain unfold. Nevertheless, the results obtained from GUM analyses should prove more stable than a simple deterministic approach.
There are currently more generation projects proposed than are essential to meet forecast demand. From experience, we consider it unlikely that all of these projects will be completed as planned. Some may slip from their planned commissioning dates while others will be terminated. At the same time, some existing plant can be expected to close down due to age alone while some may close due to competitive pressure from more efficient new market entrants or due to increasing pressure due to environmental constraints. We are not attempting to predict specific generation openings and closures, yet we need to know their probable effects on the power flows on the transmission system. GUM can be used to provide us with this information.
To estimate the probable ranges of power transfer, GUM randomly selects generator openings and closures, balancing the probable generation capacity against probable peak demand and probable Plant Margin. The random selections are weighted according to a range of input information and criteria, which influence the likelihood of the station opening or closing. Weightings for station openings consider, but are not limited to, the stage of development activity for the stations (which includes issues such as consents status), environmental impact, thermal efficiency, fuel type, and availability of fuel, water, and transmission. Weightings for station closure include, but are not limited to, age, thermal efficiency, fuel delivery, fuel type, availability and environmental impact.
By making random selections of demand and generation according to the given probability functions and weightings, GUM generates up to 10,000 demand/generation permutations or backgrounds. Each single background represents a time sequence of demand growth, plant openings and plant closures running from 2006/07 to 2012/13.
However, a typical GUM analysis does not model every possible future; rather it represents a possible range of variations around the overall demand growth forecast and range of possibilities within the current list of generation projects. Changing the underlying assumptions (for example, a major change in relative fuel costs, or changes in the location and timing of new generation projects) would have some effect on the power transfer ranges.
For each of the 10,000 backgrounds, GUM calculates the net generation capacity surplus or deficit for each specified GUM zone or group of GUM zones. This surplus or deficit then permits the calculation of the range of possible transfers out of or into each specified zone or group of zones for each sampled generation background. By calculating the net transfer for each of the 10,000 backgrounds within each year of the study period, it is possible to show probabilistic ranges of net transfers into or out of each specified zone, or group of zones, year by year. The program only considers net transfers. Since GUM does not incorporate a network model, it does not in itself calculate power flows across individual circuits.
As with the deterministic analyses, it is useful to consider probabilistic power transfers across certain critical boundaries. The GUM analyses presented in this chapter are based around the SYS Boundaries and SYS Study Zones introduced in SYS Boundaries and SYS Study Zones. Since GUM calculates net imports and exports for zones and groups of zones, all GUM boundaries are defined in terms of the complete boundary surrounding specified single zones or groups of zones.
Accordingly, each boundary under study is defined in terms of the zones on one side of that boundary. Table 8.1 lists the defining zones on one side of each of the main SYS boundaries. For boundaries B10, B12, B13 & B15 the defining zones are south of the boundary. For boundaries B3, B14 & B17 the defining zones are those encompassed by the boundary. For all other boundaries, the defining zones are north of the boundary.
A key output of GUM is the probabilistic range of transfers over a given period for each defined boundary. For each year of the study, GUM calculates probabilistic distributions of power transfers for each boundary under peak load conditions. These distributions could be plotted as separate charts for each boundary for each year. However, a concise and convenient method of presenting the results is to plot percentiles of the distributions to show how the range of probable transfers varies year by year for each boundary.
The resultant plots typically display a narrower range of transfers in the earlier years than in the later years, since there is greater certainty associated with the earlier years. The characteristic shape is therefore generally in the form of a fan and, in view of this, the diagrams are often referred to as "fan diagrams".
An illustrative example is given in Figure 8.3. The green shaded area shows the range of probabilistically derived transfers arising out of the GUM analyses. The deterministic SYS planned transfer, the deterministic SYS required capability and the deterministic SYS capability have been superimposed on top of the "fan" of probabilistic transfers for comparison.
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In the illustrative example of Figure 8.3, the darker shaded central band extends (on the vertical axis) from the 25th to the 75th percentiles of the range of probabilistically derived transfers, and thus includes 50% of all such transfers across the boundary at the time of system peak. The wider area, encompassed by the lighter shaded bands runs from the 5th to the 95th percentile and thus, together with the dark band, includes 90% of transfers. The remaining 10% lie outside the shaded range. The fan of probabilistically derived transfers can be compared with the deterministic planned transfer for the single deterministic SYS background.
It does not follow that the probabilistic transfer arising from a background considered to be likely will necessarily be captured within the envelope range shown on the diagram. Nor does it follow that all the most commonly occurring transfers have highly probable backgrounds. In GUM, all backgrounds are equally probable. Nevertheless, the range of transfers displayed in the fan diagram does provide a very useful indicator of the most probable future planned transfer across the boundary given the possible combined effects of the various sources of generation and demand uncertainty. GUM can then be interrogated to reveal the details of any background underlying any transfer (point on the fan diagram) for further detailed analysis.
GUM takes as its starting point the existing pattern of zonal demand and generation at the time of the 2005/06 winter peak. Conditions in the first year thereafter should be fairly predictable, nevertheless there are uncertainties that are represented in GUM's probabilistic analysis. For example, a power station may be scheduled to commission by the 2006/07 winter peak, but construction may slip such that it is unable to contribute to the system peak demand until 2007/08. Variations and uncertainties relating to transfers across the External Interconnections with External Systems are included in the probabilistic analyses. This can account for a significant part of the range of uncertainty displayed in the fan diagrams.
The arbitrary example given in Figure 8.3 the deterministic SYS required capability exceeds the SYS boundary capability by year four, which implies that there are no opportunities for additional generation on the exporting side of the boundary from that year without reinforcement. The probabilistic transfers, indicated by the fan, imply that the need for reinforcement is unlikely until the later years, if at all. Any reinforcement can therefore be delayed until the later years when the need becomes more certain.
However, as noted previously, these kinds of conclusions must be qualified by recognition that the boundary capability is dependent on the exact disposition of generation and demand in the background against which it is assessed. For example, interactions of generation openings and closures and changes in demand all on the same side of a boundary, or on opposite sides, can lead to little or no change in the 'Planned' boundary transfer but, nevertheless could give rise to a need for significant reinforcements in order to maintain system security. Nor would two backgrounds, which, result in similar transfers across a particular boundary necessarily, give rise to the need for the same transmission reinforcement across that boundary since the boundary capability is a function of how the boundary transfer is shared between the boundary circuits, which is in turn a function of the particular background under consideration.
An important message is that the requirement for transmission system reinforcement does not simply correspond to a given boundary transfer. The need for system reinforcement can still arise at transfers below the 'SYS capability' levels displayed in the series of figures (i.e. Figure 8.B1 to Figure 8.B17) included in the next section of this chapter.
For a better understanding of the results presented in this section the reader is advised to first read the previous sections of this chapter. In particular the format of the figures used is as presented in Figure 8.3. The SYS background transfers presented are consistent with the power flow studies discussed in GB Transmission System Performance which were also based on the generation ranking order of operation given in Table 7.1.
Please note that the transfers displayed in the series of figures which follow (i.e. Figure 8.B1 to Figure 8.B17) relate to the time of system peak demand. The capabilities shown are the transfer levels beyond which either thermal or voltage limitations become apparent on the Main Interconnected Transmission System. These SYS capabilities have been evaluated for the spot years 2006/07, 2008/09, 2010/11 and 1012/13 only. It is stressed that the SYS capabilities are appropriate for the SYS background and do not necessarily correspond to any of the many backgrounds appropriate to the probabilistic transfer range. The SYS capability does nevertheless provide a useful reference and initial indicator of overall capability.
The probabilistic transfer ranges shown are considered to be a more realistic representation of the likely transfer range than the single deterministic SYS background transfers and naturally receive attention in the commentary that follows. However, apart from a high level comparison, it is not possible to provide a detailed commentary on the probabilistic ranges since to do so could breach our obligations to our customers on commercial confidentiality. For the single deterministic SYS background transfers this is not a concern and accordingly greater detail has been included in the commentary.
In considering each of the following boundary commentaries it is useful to cross reference a number of tables presented elsewhere which are relevant to the SYS background transfers. Table 7.2 presents the SYS background studied generation, demand and transfer for each boundary. For ease of reference, each of the following boundary commentaries include the relevant extract of Table 7.2 . Please refer to Table 3.7 for details of generation capacity changes under the SYS background over the period from 2000/01 to 2012/13, Table 3.10 for generation disconnections since 2000/01 and to Table 3.11 generating units declared unavailable.
As explained in Chapter 3, access to the GB transmission system is provided through arrangements with National Grid, acting as GBSO, under the Connection and Use of System Code (CUSC). The CUSC sets out the contractual framework for connection to, and use of, the GB transmission system. The CUSC has applied across the whole of Great Britain since BETTA "go-live" (1 April 2005).
However, prior to BETTA "go-live", the CUSC applied in England and Wales but different arrangements applied in Scotland. The pre BETTA go-live generation offers and agreements between relevant TOs and Users needed to be converted into GB Offers. Condition C18 ("Requirement to offer terms for connection or use of the GB transmission system during the transition period") of Section E ("Transitional Standard Licence Conditions") of the Electricity Transmission Licence placed certain obligations relating to this on National Grid as GBSO. The principal objectives of C18 were to ensure that National Grid, as GBSO, had:
As GBSO, National Grid is obliged to make offers to existing and prospective new generation and demand customers for connection to and use of the GB transmission system. The two Scottish Transmission Licensees are obliged to make offers to the GBSO in relation to connections to their respective systems. All offers must permit compliance with the Licence Standard and, where necessary, offers will include specification of transmission reinforcement works that are required to be completed before connection to or use of the system is allowed.
Much consideration has been given to how transmission access rights should be allocated to individual "existing" Users and applicants under BETTA. For this purpose, the parties that needed, or need, to receive GB Offers before and after BETTA go live have been divided into four main GB Offer Groups. These four GB Offer Groups are defined in the Glossary but have been reiterated here for ease of reference.
Group A:
This group includes parties who, at 1st September 2004, were existing Users (i.e. had accepted an Offer).
Group B:
This group includes parties who had applied for connection or use of system prior to 1st January 2005 but who are not in Group A.
Group C:
This group includes parties who applied for connection or use of system in the period from 1st January 2005 to 31st March 2005.
Group D:
This group includes parties who have applied for connection or use of system from 1st April 2005.
The removal, under BETTA, of the previous commercial arrangements for the use of the circuits connecting Scotland and England has given wider rights of GB system access than previously was the case. However, the volume of requirements for connection to and use the GB transmission system has meant that:
The results, reported in this chapter, demonstrate this potential transmission capacity shortage under the SYS background. As a consequence, there is a potential need for significant reinforcement of the system in addition to those identified in Table 6.2.
The enduring BETTA arrangements require that all transmission Users have Connection or Use of System Agreements with the GBSO (i.e. 'GB agreements'); any pre-BETTA Connection or Use of System Agreements with any of the three Transmission Licensees are be superseded. The aforementioned shortage of transmission system capacity and the arrangements, directed by Ofgem, for the transition from pre-BETTA to post-BETTA position meant
that a number of system Users will have been made offers of 'GB agreements' that differ from any previous Connection or Use of System Agreement and will:
After the introduction of BETTA , which brought about the removal of the administered Interconnection arrangements between England and Scotland an extensive reinforcement programme is required to accommodate the required capabilities determined by the SYS background for boundaries in the border area.
Examination of the boundary transfer levels over the seven year period for the 'SYS background' indicates that:
Comparison of the SYS Planned Transfers with the probabilistic ranges reveals that:
Examination of Figures 8.B1 to Figure 8.B17 reveals a wide range in the width of the probabilistic transfer envelope across the various boundaries. For boundaries cutting large importing or exporting areas such as Boundary 8 (North to Midlands) and Boundary 9 (Midlands to South), the width of the probabilistic transfer envelope reflects, inter alia, the higher uncertainty associated with the larger tranche of generating plant on the exporting side. For other boundaries, such as Boundary 14 (London) which is an importing boundary dominated by a large demand with little generation, the width of the probabilistic transfer envelope is relatively narrow reflecting a higher degree of certainty.
Boundaries B6 (SPT - NGET), B7 (Upper North), B10 (South Coast import), B11 (Northeast & Yorkshire), South & Southwest import (B12), South West import (B13) and B16 (Northeast, Trent & Yorkshire) would all require reinforcement to be Licence Compliant for the SYS background.
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Generation to the north of this boundary is increasing at a significant rate due to the high volume of new wind based generation seeking connection in the area. Consequently, the boundary transfers are also increasing at a similar rate.
Please note that application of the Interconnection Allowance (or part thereof) relates only to those boundaries, which divide the system into two contiguous parts, the smaller of which contains more than 1500MW of demand. For this boundary (as with boundaries B2 and B3), this is not the case and accordingly the required capability is equal to the Planned Transfer.
The 2006/07 required capability for this boundary is just within the actual boundary capability. However, in 2007/08 the planned transfer exceeds the actual boundary transfer indicating the need for transmission reinforcement. In practice, generation will only be connected up to the limit of the boundary until the transmission reinforcement has been completed.
The first of the proposed reinforcements for this boundary is the replacement of the existing 132kV double circuit tower line between Beauly, Fort Augustus, Errochty and Bonnybridge, by a new 400kV double circuit tower line terminating at Denny near Bonnybridge. Subject to wayleave and planning consents, this reinforcement referred to as Beauly-Denny will increase this boundary capability from 400MW to 1100MW. The additional generation connecting to the north of this boundary means that further reinforcement of this boundary will be required. The proposed reinforcement in this case is strengthening of the transmission infrastructure between Beauly (near Inverness) and Keith/Blackhillock. As a first step the boundary capability can be raised to around 1400MW by reconductoring the existing transmission line between Beauly and Blackhillock. Further reinforcement between Beauly and Keith/Blackhillock could be provided in the form of a new transmission line. Furthermore, if the generation volumes warrant it then the transmission capacity can be increased by completion of a 400kV ring from Denny to Kincardine (via Errochty, Fort Augustus, Beauly, Keith, Kintore and Tealing). The 400kV ring can be achieved by making use of the proposed new line routes established between Beauly and Denny and between Beauly and Keith/Blackhillock as mentioned above, and using existing infrastructure from Keith down the east coast to Kincardine which is already constructed to 400kV.
Within the north west boundary, additional transmission reinforcements will be required to connect the proposed new generation. For example, to the north of Beauly, additional works between Beauly and Dounreay (near Thurso) will be required. This will comprise conductoring the spare side of the existing 275kV double circuit line between Beauly and Dounreay and installation of a 275kV busbar and a second 275/132kV transformer at Dounreay. Further reinforcement north of Beauly may be required depending on the location and volume of generation connections.
The significant interest from generation developers on the large Island groups of the Western Isles, Orkney and Shetland means that infrastructure will be required to connect these to the mainland transmission network.
The routes for all new transmission infrastructure will undergo detailed environmental impact assessment and will be subject to consents and planning approval.
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Generation to the north of this boundary is increasing at a significant rate due to the high volume of new renewable generation seeking connection to the north of this boundary. Consequently, the boundary transfers are also increasing at a similar rate.
Please note that application of the Interconnection Allowance (or part thereof) relates only to those boundaries, which divide the system into two contiguous parts, the smaller of which contains more than 1500MW of demand. For this boundary (as with boundaries B1 and B3), this is not the case and accordingly the required capability is equal to the Planned Transfer.
The required capability of this boundary indicates the need to reinforce the transmission system in this location. The proposed Beauly to Denny reinforcement required for the north west boundary will also relieve this boundary. The reinforcement comprises the replacement of the existing 132kV double circuit tower line between Beauly, Fort Augustus, Errochty and Bonnybridge, by a new 400kV double circuit tower line terminating at Denny near Bonnybridge. Subject to wayleave and planning consents, this reinforcement will increase the north south boundary capability from 1600MW to 2400MW by 2009. Due to a voltage restriction in 2010/11, reactive compensation at Tealing is required which further increases the boundary transfer capability to 2600MW. Depending on the volume of future renewable generation applications, additional reinforcement of this boundary may be required. This could include the creation of a 400kV ring from Denny to Kincardine (via Errochty, Fort Augustus, Beauly, Keith, Kintore and Tealing). As described above, the 400kV ring can be achieved by making use of the proposed new line routes established between Beauly and Denny and between Beauly and Keith/Blackhillock, and using existing infrastructure from Keith down the east coast to Kincardine which is already constructed to 400kV.
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Please note that application of the Interconnection Allowance (or part thereof) relates only to those boundaries, which divide the system into two contiguous parts, the smaller of which contains more than 1500MW of demand. For this boundary (as with boundaries B1 and B2), this is not the case and accordingly the required capability is equal to the Planned Transfer.
New renewable generation in Kintyre and Argyll is increasing over time and reinforcement is needed to accommodate the required capability from 2007/08. The proposed reinforcement to increase the boundary capability from 210MW to 400MW is a new 275/132kV substation which links the Killin to Sloy 132kV line with the 275kV line which runs from Windyhill to Dalmally. The substation would be located at a point near to where the lines cross at the north end of Loch Lomond.
A considerable volume of generation applications within this boundary have been received which, if contracted, will require additional reinforcement within this area. A number of reinforcement schemes are being considered to provide additional transmission capacity in the area.
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The SHETL to SPT boundary defines the asset ownership boundary between SHETL and SPT and runs from the firth of Tay in the east to near the head of Loch Long in the west. This boundary encompasses all the generation and demand (except for Dunoon and Strathleven) in the SHETL area and is normally an exporting boundary.
Generation to the north of this boundary is increasing over time due to the high volume of new renewable generation seeking connection in the SHETL area. Consequently, the boundary transfers are also increasing with time.
Please note that application of the Interconnection Allowance (or part thereof) relates only to those boundaries, which divide the system into two contiguous parts, the smaller of which contains more than 1500MW of demand. For this boundary, Interconnection allowance is applicable and is added to the Planned Transfer to give the required capability for the boundary.
The required transfer capability from 2007/08 indicates the need to reinforce the transmission system in this location. The proposed Beauly to Denny reinforcement outlined for the north west boundary will also increase the capacity of this boundary. The Beauly to Denny reinforcement comprises the replacement of the existing 132kV double circuit tower line between Beauly, Fort Augustus, Errochty and Bonnybridge, by a new 400kV double circuit tower line terminating at Denny near Bonnybridge. This reinforcement will increase the boundary capability from 1500MW to around 2600MW by 2009.
The growing volume of renewable generation connections in the SHETL area requires that further reinforcement is carried out. Due to a voltage restriction in 2010/11, reactive compensation at Tealing is required which increases the boundary capability to 2800MW. Depending on the volume of future renewable generation applications, additional reinforcement of this boundary may be required. This could include the creation of a 400kV ring from Denny to Kincardine (via Errochty, Fort Augustus, Beauly, Keith, Kintore and Tealing). As described above, the 400kV ring can be achieved by making use of the proposed new line routes established between Beauly and Denny and between Beauly and Keith/Blackhillock, and using existing infrastructure from Keith down the east coast to Kincardine which is already constructed to 400kV.
In practice, generation will only be connected up to the limit of the boundary until the reinforcement is completed.
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The north to south transfer across this boundary in the central belt of Scotland shows a rise throughout the years of this statement, due primarily to contracted renewable energy developments in the north of Scotland. The main increase takes place between 2006/07 and 2010/11, whilst the increase is more moderate in later years given the anticipated programme of generation commissioning. As a consequence, the required capability rises to a level in excess of the current capability in the first two years; indicating a need for reinforcement. The potential shortfall in capacity in 2006/07 is in part due to the difference in timing between the regional maximum demand and GB maximum demand.
SPT intend two stages of reinforcement. The first stage will involve installing a series reactor on the Windyhill to Neilston 275kV circuit. The thermal capability of the Longannet to Easterhouse and Longannet to Clyde's Mill 275kV circuits will be enhanced via switchgear replacement at Easterhouse and Clyde's Mill 275kV substations. The second stage will include thermal uprating/ reconfiguration of a number of 275kV circuits and installation of reactive compensation at Kincardine and Denny North 275kV substations. These works will be co-ordinated with delivery of upgrade on the SPT-NGET and SPT-SHETL boundaries.
It can be seen from the probabilistic range of transfers (in which the SYS Planned Transfer lies near the 50th percentile of GUM transfers by 2012) that there is a high probability of these reinforcement being required.
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The north to south transfer across the boundary between SPT and NGET shows a significant rise throughout the years of this statement, due primarily to contracted renewable energy developments throughout Scotland. The main increase takes place between 2006/07 and 2008/09 whilst the increase is more moderate in later years given the anticipated programme of generation commissioning. As a consequence, the required capability rises to a level significantly in excess of the current capability, indicating a strong and urgent need for reinforcement.
Due to the fact that the required capability currently exceeds the actual capability, SPT and NGET have been granted relief from Licence Condition D3 in respect of the circuits connecting the SPT transmission system to that of National Grid. The period for which relief has been granted expires in April 2007. In view of the lead-time to complete the necessary reinforcements, SPT and NGET will seek an extension to this period.
To achieve a capability of approximately 2,800MW in year 2010/11 SPT and NGET intend to undertake an extensive reinforcement programme. The existing 275kV link from Strathaven to Harker will be uprated to 400kV operation. The overhead line conductor on the Eccles to Stella West 400kV circuits will be replaced with a conductor bundle that gives a higher continuous rating as well as lower impedance, enhancing boundary thermal and stability performance. A new 400 kV substation will be established at Blyth and connected into the Eccles to Stella West circuits. The network will be reconfigured at Hawick and the quadrature booster at Tongland replaced with a unit of higher rating to manage power flows through the 132kV network.
Upon completion of the above works, the boundary continues to show insufficient transfer capability, indicating a further extensive reinforcement programme is required. The following proposals provide a 'best view' on the infrastructure upgrades necessary to restore licence compliance for the SYS background; until detailed site and construction evaluations are completed, they should be regarded as indicative.
The programme is likely to include a second 400/275kV transformer at Strathaven and establishment of reactive compensation plant at Strathaven, Neilston and Kilmarnock South in Scotland and locations in the north of England to provide post-fault voltage compliance. One of the circuits between Blyth and Hawthorn Pit will be upgraded to 400kV. The circuits between Heysham and Hambleton t-point will be re-conducted to enhance thermal capability. A third cross-boundary transmission route to form Kilmarno ck - Harker and Harker - Heysham double circuits will be necessary. Furthermore, additional thermal enhancement is required for some circuits downstream of Hambleton by 2011/12.
The SYS Planned Transfer lies above the 50th percentile in the probabilistic range of transfers while the SYS capability is in the lower parts. There is hence a chance of lower peak flows than suggested by the SYS background; however, significant reinforcements will nevertheless be required in the very near future to facilitate even the lower parts of the range of probabilistic transfers.
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The Upper North boundary experiences a large transfer increase between 2006/07 and 2008/09, as a consequence of the significantly increased export from Scotland into England from new renewable generation connections.
The boundary shows insufficient transfer capability from 2009/10 onwards. Compliance however can be restored with the outlined SPT - NGC boundary reinforcements.
The planned transfer lies between the 50% and 90% range of probabilistic transfers. Note that as the SYS transfer increases from 2007/08 to 2008/09 there is a corresponding increase in the probabilistic transfers. This shows a potential increase in transfers due to plant commissioning North of Boundary B7 during early years of the SYS period. From 2010/2011 the boundary capability is insufficient to accommodate most of the probabilistic range of transfers indicating a likely need for additional reinforcements, however the required transfer is outside the 90% of probabilistic transfers which indicates that the chance of this transfer being exceeded is low.
Note also that the SYS capability from 2010/2011 onwards have reduced due to the inclusion of the Western and Eastern interconnectors. The inclusion of Anglo-Scottish reinforcements without further reinforcements south of the SPT - NGC boundary creates a lower impedance route and thus greater flows across critical circuits.
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The SYS transfers increase between years 2006/07 and 2009/10, mainly because of the contractual position of new generation to the north of the boundary in the SYS background. However, for years following 2008/2009 the transfer decreases due to new generation opening to the south of the boundary
SYS studies suggest that the boundary capability will remain above the SYS required transfer throughout the SYS period.
For the entirety of the planned period the SYS planned transfers lie at the lower end of the likely range of probabilistic transfers. This shows that there is a significant probability of the actual transfers across this boundary being higher than the transfers indicated by the SYS background.
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The trend for boundary 9 is similar to that for the North to Midlands boundary with an increased SYS transfer between 2006/07 and 2008/09, mainly because of new generation to the North of the boundary in the SYS background. The planned SYS transfer decrease after 2009/10 due to new generation openings in the south of boundary which will displace some of the generation in the north of the boundary.
The boundary capability is shown to be marginally higher than the required transfer throughout the SYS period. The required transfers lies outside the 90% range until 2010/2011 which means a lower risk of it being exceeded. The capability lies outside the 90% range and thus reinforcements are unlikely to be required.
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The SYS transfers decreases gradually from 2006/07 to 2008/09 due to new generation openings in the South Coast area. However, the SYS transfers increase marginally from 2009/10 onwards, mainly due to steady demand growth.
The boundary capability is below the required transfer from 2007/08 onward. The requirement for reinforcements is more likely towards the latter end of the SYS period.
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The transfer across boundary 11 shows an increase between 2006/07 and 2009/10 due to the increased exports from Scotland.
There is insufficient boundary capability from 2007/08 onwards, although this can be resolved with the reinforcements proposed for boundary 6.
The SYS transfer is in the 50% probabilistic range, and the required capability remains in the 90% of range of probabilistic transfers. This demonstrates the highly probable need for B6 reinforcements.
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New generation projects on the importing side of the South and South West boundary result in a significant reduction of boundary transfer between years 2006/07 and 2012/13.
The SYS Planned Transfer is above the 90th percentile of transfers in 2006/07, however following 2006/2007 there is a significant probability of the SYS transfer being exceeded. The same is true for the required capability and SYS capability. This is due to the significant increase in generation in exporting part of the boundary. It is highly likely that reinforcements will be required to cope with the increased transfers across this boundary.
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The SYS Planned Transfer decreases steadily from 2006/07 and remains at lower levels than that of 2006/07 due to a general trend in increased generation plant in the Southwest peninsula.
The spread of likely transfers is extremely narrow until 2007/08, which is representative of the lack of proposed generation developments in the group during the initial year. The probabilistic transfer then begins to widen out reflecting uncertainties associated with possible new generation and station closures in the group. The SYS Transfer and SYS required capability are likely to be exceeded, and the transfers are likely to exceed the SYS capability from 2008/09 onwards, suggesting that further reinforcement will be required.
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London imports a significant proportion of its demand. Over the SYS period planned transfer increases gradually, primarily as a result of demand growth.
The boundary capability is higher than the required capability for the whole period, increasing from 20010/11 due to reinforcements such as Kemsley QBs, triggered by increasing generation in the Thames Estuary.
The spread of likely transfers for Boundary 14 is narrow due to the high level of demand and the relatively low volatility and volume of the generation in the group. The SYS transfers are outside the probabilistic range from 2008/09 indicating that further reinforcements are is unlikely to be necessary. However, it should be noted that the actual capability for London import is particularly sensitive to availability of specific generating units within London and the South East, which in turn influences which circuits are most utilised and hence the proximity to limits.
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The effective generation in the Thames Estuary is approximately three times larger than the zone's demand. Therefore, a large amount of power is exported into the Southeast of England from generation in Kent and Essex. The area demand grows steadily throughout the SYS period, and the amount of effective generation increases as more generation in this area comes into service. There is a large increase in thermal capability due to reinforcements required for new generation projects; however the capability for 2010/11 is limited by voltage issues. The capability of the boundary can accommodate the required transfer for the SYS background throughout the SYS period.
The SYS Planned Transfer lies at the top end of the probabilistic transfers throughout the entire period. With the boundary capability exceeding the SYS Required Capability, additional reinforcements above those already included in the SYS background are unlikely to be needed for this boundary.
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New generation openings and steady demand increase characterise this boundary. The boundary shows insufficient transmission capability throughout the entire period from 2007/2008. However, utilising the reinforcements proposed for boundary 6 can restore compliance.
The probabilistic range and SYS transfer for this boundary are fairly constant throughout the SYS period, which is reflected by the relatively moderate demand growth in the North East. The SYS capability for this boundary indicates that there is a significant likelihood that some further reinforcements additional to those outlined above will be required late in the period to facilitate higher flows.
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The West Midlands imports a significant share of its demand during this SYS period as well as supporting the bulk North to South power flows on the transmission system. Over the SYS period the required capability for the boundary decreases due to new generation openings in 2008/09. The boundary capability is higher than the requirement determined by the SYS background throughout the whole period.
The SYS Planned Transfer exceeds the 90th percentile of transfers in 2006/07, but from 2007/08 onwards there is a significant probability of the SYS transfer being exceeded.
The SYS capability for this boundary is such that only required transfers resulting from the highest probabilistic transfers in late years cannot be accommodated.
The list of reinforcement schemes presented in Table 8.2 provides an indication of those reinforcements that may be required to ensure continued compliance with the Licence Standard across the 17 major SYS boundaries at the time of peak for the given SYS background, i.e. to remedy capability deficits.
These indicative schemes would be additional to the currently planned transmission reinforcements listed in Table 6.2, and which already form part of the SYS background.
The additional schemes would be required, not only for compliance across the 17 SYS boundaries ('inter-zonal' reinforcements), but also for compliance across a number of boundaries internal to the zones delineated by the 17 SYS boundaries ('intra-zonal' reinforcements). The developments listed are those required for the specific SYS background. In the event it is likely that these additional indicative schemes would be varied to meet the changing needs of the system as it evolves.
Once the need for a particular reinforcement is confirmed the detailed specification will be considered. By way of example, for reactive compensation plant, the optimal location, size and desired performance will be the subject of detailed analyses nearer the time when there is a need to commit to the work.
As a point of interest, as a consequence of the transition towards the enduring BETTA arrangements, some of the works listed in Table 8.2 will have been made a condition of particular 'GB Agreements' for connection to and use of the GB system. That is, a condition will have been included in certain agreements stipulating that the works would have to be completed before connection to or use of the GB Transmission System is permitted. This is in order to ensure continued compliance of the system with the Licence Standard and to safeguard the interests of all Users of the GB Transmission System in respect of security of supply.
In any event, the three Transmission Licensees will continue to manage the timing of reinforcements to ensure that an efficient, co-ordinated and economic system, compliant with the License Standard is provided at all times, except where derogations have been granted or have been applied for.
The list of reinforcement schemes presented in Table 8.2 provides an indication of those reinforcements that may be required to ensure continued compliance with the Licence Standard across the 17 major SYS boundaries at the time of peak for the given SYS background, i.e. to remedy capability deficits.
These indicative schemes would be additional to the currently planned transmission reinforcements listed in Table 6.2, and which already form part of the SYS background.
The additional schemes would be required, not only for compliance across the 17 SYS boundaries ('inter-zonal' reinforcements), but also for compliance across a number of boundaries internal to the zones delineated by the 17 SYS boundaries ('intra-zonal' reinforcements). The developments listed are those required for the specific SYS background. In the event it is likely that these additional indicative schemes would be varied to meet the changing needs of the system as it evolves.
Once the need for a particular reinforcement is confirmed the detailed specification will be considered. By way of example, for reactive compensation plant, the optimal location, size and desired performance will be the subject of detailed analyses nearer the time when there is a need to commit to the work.
As a point of interest, as a consequence of the transition towards the enduring BETTA arrangements, some of the works listed in Table 8.2 will have been made a condition of particular 'GB Agreements' for connection to and use of the GB system. That is, a condition will have been included in certain agreements stipulating that the works would have to be completed before connection to or use of the GB Transmission System is permitted. This is in order to ensure continued compliance of the system with the Licence Standard and to safeguard the interests of all Users of the GB Transmission System in respect of security of supply.
In any event, the three Transmission Licensees will continue to manage the timing of reinforcements to ensure that an efficient, co-ordinated and economic system, compliant with the License Standard is provided at all times, except where derogations have been granted or have been applied for.
This chapter provides a commentary on those parts of the GB transmission system most suited to new connections and to the transport of further quantities of electricity. The information presented draws on that contained in the previous chapters. In particular GB Transmission System Capability.
Readers are reminded that anyone considering a development at a specific site requiring additional technical information relating to that site may contact us for assistance as explained in Further Information.
Notwithstanding the opportunities set out in this chapter, the three Transmission Licensees will continue to comply with Transmission Licence obligations and make offers to any User or potential new User wishing to use the GB transmission system in respect of new generation and/or demand. The timescales, required by each Transmission Licensee to complete any necessary transmission work, associated with a new development, is, amongst other things, a function of the size and location of the development. In some instances no infrastructure reinforcement work at all will be required and no delay will be incurred. That is, if the required transmission reinforcement is localised and uncontentious, the necessary work can normally be completed in similar timescales to that of the customer's project. However, where the development requires extensive and/or contentious transmission work (with the associated need for Planning Consent and possible Public Inquiries), it may not always be possible for the relevant Transmission Licensee to fully meet the customer's wishes with respect to timescales. Nevertheless, all three Transmission Licensees will always endeavour to meet their customer's requirements.
Finally, the provision of voltage support services is discussed towards the end of this chapter. Amongst other things that section presents information on possible future opportunities for Users to provide voltage support services under contract to ourselves and outline information on performance requirements for such services to help Users decide whether to approach us with an offer of service.
Interconnections With External Systems explained that our transmission system is directly interconnected with those of France, Northern Ireland and the Netherlands. Parties that have acquired rights to use these External Interconnections are, subject to the relevant market arrangements and agreements, able to trade between the electricity market in Great Britain and those of the External Systems.
Under NETA, new arrangements for obtaining access to the link were introduced and these continue under BETTA. The arrangements allow for capacity to be allocated in either direction via a system of auctions. These are jointly administered by National Grid and the French Transmission System Operator (RTE). Details of the access arrangements including the auction process can be found on the RTE and National Grid Website, namely: http://www.nationalgrid.com/uk
This link is owned by Moyle Interconnector Limited and operated by System Operator Northern Ireland (SONI), who also administer the sale of capacity on the interconnector on behalf of Moyle. The relevant Website address is: http://www.soni.ltd.uk
National Grid and NLink, a subsidiary of TenneT, the transmission system operator in the Netherlands, are developing a project for an interconnector between Britain and the Netherlands. Arrangements for providing access to this link are currently being formulated.
The majority of single new demands are less than 50MW in size (e.g. a large new car production plant). However, the demand from a new steelworks could be in the region of 150MW. In any event, a step-change of say 150MW of demand is usually too small a value to affect any single zone significantly. In general terms, there is likely to be sufficient spare capability over a whole zone of the supergrid to be able to accommodate any single new demand of this size without requiring major reinforcement into the whole zone. Reinforcements at and into a particular Grid Supply Point may be required for a new demand, and in some cases additional reactive compensation may also be required, and a prospective new entrant should contact us for a detailed discussion of an individual site.
An exception might be the introduction of such a step-change of load at certain points within in or around the London area. The London area has a large demand; approaching one tenth of the GB system peak demand. The London boundary is close to its thermal limit although planned work, some in Table 6.2 and some in Table 8.2, will ensure continued compliance. A large step-change in demand might, dependent of course on exact location, require major reinforcement into London.
In should also be remembered that, whilst a 150MW demand increase may not have an appreciable effect upon the particular zone in which it is located, it could have a more global effect on the overall system. For instance additional demand in the south could, under certain circumstances, advance the need for major inter zonal transmission reinforcement between the north and the south. Each case needs to be considered on its own merits.
In general terms, the disposition of demand and generation across the GB transmission system is such that much of the generation capacity is located in or towards the northern parts while much of the demand is located in the southern parts of the system. In consequence, the resultant power broadly flows from the northern parts to the southern parts of the system, particularly at times of the GB system peak demand.
The aggregate power station capacity is projected to rise from 76.3GW in 2006.07 to 94.5GW by 2012/13. The largest proportion of the overall increase is due to CCGT plant at 53.4% with CHP accounting for a further 3.3%. The second largest proportion of the increase is due to Wind with on-shore wind accounting for 27% and off-shore wind accounting for 18.2% of the increase. On this basis, the capacity of CCGT plant would overtake that of coal in 2008/09. By 2011/12, CCGT capacity would exceed coal capacity by 4.6GW and account for 35.6% of the total transmission contracted installed generation capacity. Similarly, wind generation capacity (both on-shore and off-shore) is set to rise to 9.4GW by 2012/13. These capacities do not include the embedded Medium and Small generation and embedded External Interconnections with External Systems. The capacity of such embedded generation sources is the subject of Embedded and Renewable Generation.
The disposition of the 18.2GW of projected increase in generating capacity is described in Generation Disposition. A key message arising from the analyses of boundary power transfers is that, with this 18.2GW increase in new generation
planned for the next seven years, the resultant power flows through the Scottish and English grid systems to the Midlands would require significant reinforcement. Of course, the future is uncertain and it may be that, given the degree of public opposition expressed towards some of the proposed renewable projects, not all may proceed to completion. In addition some existing fossil fuel stations may close for either technical reasons or for commercial reasons e.g. following the introduction of the Large Combustion Plant Directive in 2008.
In the generation context, opportunities are interpreted as the ability to connect new generation without an associated need for major transmission reinforcement which could in turn lead to delays including those which may be incurred by the need for Planning Consent and possible Public Inquiry.
GB generation agreements are conditional on the completion of the required reinforcements to maintain compliance with the Licence Standard. A particular case in point is the SPTL - NGET boundary (Boundary B6), where there is insufficient transmission capacity to accommodate the level of contracted generation in Scotland. The SYS background power flows across major boundaries within Scotland have also been shown to exceed their boundary capabilities, in particular boundaries 1, 2, 4 and 5 (SHETL North West, SHETL North - South, SHETL to SPTL and North to South SPTL respectively).
A further consequence of the connection of 'contracted' generation in Scotland is that there is insufficient capacity on some boundaries within England, in particular the Upper North - North (Boundary B7), North East and Yorkshire (Boundary 11) and North East, Trent and Yorkshire (Boundary B16) boundaries. By 2007/08 these boundaries will be non-compliant for the SYS background. Furthermore, the probabilistic assessment in the previous chapter indicates a rather high likelihood of insufficient capacity for the North - Midlands (Boundary 8).
These circumstances lead to significant constraints and, depending on location, connection dates may be subject to delays until major system reinforcements are completed; applications for generation in the north received after 1st January 2005 are more likely to be subject to longer delays. The system reinforcements concerned are mainly within Scotland and around the SPTL-NGET boundary. A significant proportion of these reinforcement works are unlikely to be completed much before 2010. As a result there is unlikely to be any opportunity for new applicants to connect generation at any point to the north of the North - Midlands boundary (Boundary B8) within the seven year period covered by this Statement.
It is worth stressing that the deterministic SYS background has been used as the basis of the studies for determining the transmission capacity required to accommodate the current generation 'contracted' position and for determining when further generation can be accommodated onto the GB transmission system. However, in view of the level of uncertainty associated with the future outturn, it would be misleading and inappropriate to attempt to provide precise numerical guidance with regard to opportunities. More usefully, we are able to provide an overview based on the information presented in other chapters of this Statement; in particular the boundary transfers, Figure 8.B1 , Figure 8.B2 , Figure 8.B3 , Figure 8.B4 , Figure 8.B5 , Figure 8.B6 , Figure 8.B7 , Figure 8.B8 , Figure 8.B9 , Figure 8.B10 , Figure 8.B11 , Figure 8.B12 , Figure 8.B13 , Figure 8.B14 , Figure 8.B15 , Figure 8.B16 and Figure 8.B17, see GB Transmission System Capability . Additional information on zonal generation opportunities is given in Zonal Commentary later in this chapter.
Figure 9.1 provides a summary of the opportunities available in the 17 SYS Study Zones. The 17 zones have been grouped into five opportunity groups, namely: VERY LOW, LOW, MEDIUM, HIGH AND VERY HIGH. These categorisations are intended to provide a broad indication of the relative level of possible opportunities for connection within individual zones, or groups of zones, without the need for further major inter-zonal transmission reinforcement, which would be likely to incur significant delays in the proposed project.
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It does not follow that all the generation capacity within an opportunity group could be located at one site within a zone. In some zones, for example the London (zone 14), a considerable spread would be necessary. Nor does it follow that the capacities indicated for each zone within an opportunity group could be accepted together.
The above guidance is necessarily general and emphasises the need to consider individual prospective generation developments on their merits at the time of application. The zonal commentary section presented later in this chapter considers opportunities under both the 'SYS background' and the probabilistic backgrounds.
As mentioned in the introduction to this chapter, notwithstanding the above opportunity messages, we will continue to comply with our licence obligations to make offers and we will endeavour to meet our customers' requirements including those relating to timescales.
It was explained in Zonal Power Losses that the effectiveness, in system terms of any new generating station is related, in part, to the effect it has on system losses. Clearly, if it is placed in the north, increasing the north to south power flows, the losses will also increase so some of the output of the new station is lost to the system. However, if placed in the south the converse is true; power flows decrease, system losses decrease and the relative net effect is as if a larger station had been installed.
Table 7.5 illustrates the relative effectiveness of siting generation in each of the 17 SYS Study Zones. The ranking order displayed in Table 7.5 broadly follows the ranking of generation opportunities of the previous section and the ranking order of generation TNUoS charges.
For comparison, Schedule 1 of our 2006/07 'Statement of Use of System Charges', is reproduced in Table 9.1 - Generation and Table 9.2 - Demand.
This section complements the previous sections of this chapter by providing additional information on opportunities for new generation capacity presented on the basis of individual zones or groups of zones. The following zonal commentary considers the opportunities for new generation on the probabilistic background as well as the SYS background.
The Boundary Commentary describes the wide range of probabilistic transfers across the 17 SYS boundaries over the next seven-year period. The reader is guided to the description of the probabilistic transfers for each boundary shown in Figure 8.B1 , Figure 8.B2 , Figure 8.B3 , Figure 8.B4 , Figure 8.B5 , Figure 8.B6 , Figure 8.B7 , Figure 8.B8 , Figure 8.B9 , Figure 8.B10 , Figure 8.B11 , Figure 8.B12 , Figure 8.B13 , Figure 8.B14 , Figure 8.B15 , Figure 8.B16 and Figure 8.B17 within this section. The adoption of a probabilistic view of future boundary transfer levels recognises the fact that there is uncertainty in the future generation and demand background. Clearly, this has an impact on the likely opportunities for the connection of new generation onto the transmission network. The commentary below seeks to address the opportunities for new generation given this level of uncertainty.
Clearly, generation and demand backgrounds, which increase North to South transfers, tend to precipitate the need for major inter-zonal transmission reinforcement and thereby reduce northern opportunities. Such backgrounds would include further northern planting and/or the export of power to France at times of peak. Conversely backgrounds which reduce north to south transfers tend to increase northern opportunities and/or relax the need for major inter-zonal transmission reinforcement. Such backgrounds would include new generation in the South.
In considering the following zonal commentary it is useful to cross reference Table 7.2 , which presents the studied generation, demand and transfer for each zone and the boundary commentary in Boundary Commentary. Please note, however, that Table 7.2 is on the basis of the 'SYS background' and that the generation capacities given are the 'studied' or contributory capacities (based on Table 7.1) rather than installed capacities.
For ease of reference, each zonal commentary includes the relevant extract of Table 7.2 together with a summary of generation capacity changes in the period 2005/06 to 2011/12 based on Table 3.7 . Please refer to Table 7.1 for the effect of generation capacity changes in terms of other plant displaced from being contributory under the SYS background. Finally, the changes in generation capacity from 2006/07 to 2012/13 are described for each zone in various tables in Chapter 3; Table 3.7 and Table 3.13 in particular.
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The SHETL North West zone encompasses the area to the north and west of Fort Augustus, Beauly (near Inverness) and Keith. This area includes a significant amount of existing hydro generation, new renewable generation and the Foyers pumped storage scheme. Demand in this zone is significantly lower than the installed generation; consequently this zone is normally an exporting zone.
Generation in this zone is increasing at a significant rate due to the high volume of new renewable generation seeking connection in the area. Consequently, opportunities for connection of new generation are Very Low in this zone.
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The SHETL North zone comprises the area to the north of Errochty and Tealing, and to the east of a line drawn between Keith and Errochty. This area includes the thermal power station at Peterhead and some new renewable generation. Demand in this zone is significantly lower than the installed generation; consequently this zone is normally an exporting zone.
Generation in this zone is increasing gradually due to the connection of new renewable generation in the area. Consequently, opportunities for connection of new generation are Very Low in this zone.
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Zone 3 encompasses the southern part of the SHETL system outside of the Sloy zone. In view of the system limitations to the south of this zone, opportunities for connection of new generation are Very Low in this zone.
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The Sloy zone in the south west of the SHETL system encompasses the flows to the north and south of the Sloy busbar. In comparison to the 132kV infrastructure in the area, this boundary includes a significant amount of existing hydro generation and new renewable generation in Kintyre and Argyll. Demand in the area is centred around Oban and Mull, Lochgilphead and Islay and Campbeltown and Arran. The power flows are normally into this zone from Killin in the north and out of the zone to the south towards Windyhill (near Glasgow).
New renewable generation in Kintyre and Argyll is increasing over time and reinforcement is needed to accommodate the required capability. Consequently, opportunities for connection of new generation are Very Low in this zone.
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In view of the system limitations within and to the south of this zone, opportunities for connection of new generation are Very Low in this zone.
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In view of the system limitations within and to the south of this zone, opportunities for connection of new generation are Very Low in this zone.
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Zone 7 is located between the SPTL to NGET and Upper North to North boundaries where exports to the South are carried on three 400kV double circuits, one in the west from Harker to Hutton and two in the east from Norton to Osbaldwick and Lackenby to Thornton.
Both the deterministic and probabilistic boundary analyses in the previous chapter indicated that there is little opportunity for further generation to connect in this zone.
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The zone includes the large concentration of CCGT generation on Humberside and also a significant share of coal fuelled generation. Zone 8 has a large surplus of generation over demand and provides a path for northern exports towards southern regions.
The heavy concentration of existing and transmission contracted generating on Humberside means that there is a very limited opportunity for additional generation in this part of Zone 8. In the remainder of the zone, opportunity is limited by the ability of the North East & Yorkshire boundary to carry additional power transfers.
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This zone is enclosed by the North East & Yorkshire boundary among others towards the East and the North to Midlands boundary in the South. The generation and demand within the zone is close to equal; nonetheless, the main interconnecting circuits out of the zone support a general North to South transport of power through the zone.
The probabilistic analyses in the previous chapter showed a high probability of actual peak flows in excess of the capability of the North to Midlands boundary. A consequence of new generation connections in Zone 8 to East of Zone 9 would be a 'spill' of power westwards and then south through Zone 9 under certain fault outage conditions thus limiting opportunities in Zone 9. In any case, major circuits within Zone 9 would become overloaded were any new generation to connect to the North or West of them without reinforcements. Thus, the opportunity for new generation projects within this zone is considered low.
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This zone is enclosed by the North to Midlands boundary towards the North and the North East, Trent & Yorkshire boundary towards the South and has a large surplus of generation. The boundary capability assessment indicated no future spare capacity for the North East, Trent & Yorkshire boundary for latter years and new generation projects in the zone are therefore likely to require additional reinforcements. Opportunities for new generation within Zone 10 generally are Low.
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Zone 11 covers much of the West Midlands. This zone lies between the critical 'North to Midlands' and 'Midlands to South' boundaries and carries a high level of north to south power transfer. The local transmission system comprises a 400kV outer ring to which a number of large coal fired generating stations are connected and a local 275kV system which serves the West Midlands conurbation.
There are two underlying system characteristics, which dominate development within the West Midlands. First there is a large power transfer through the zone from north to south. Secondly, most of the demand within Zone 11 is supplied from the local 275kV system, which has little generation support. The 275kV system has historically been supported by medium and small coal fired generating plant connected at 275kV and also at 132kV. All of this has now closed and the loss of generation support has resulted in increased power transfers from 400kV into the 275kV system. Overall opportunities remain for the connection of generation within the zone, particularly medium sized developments within the 275kV system. Further opportunities for new generation would arise given any closures of existing generation.
There are no new generation projects contracted for Zone 11 at in the 2005 SYS background and there is a 'high' opportunity for new generation as detailed above. Despite this, large-scale generation projects connecting to the 275kV network would require reinforcement.
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This zone is enclosed by the Midlands to South, South and South West, London and Thames Estuary boundaries. The zone has a significant deficit of generation and strongly contributes to transport of power from North towards the South. New generation within this zone would serve to reduce the power flow from the North but could lead to a requirement to reinforce the transmission network across the north of London. The opportunity for new projects within the zone is considered as 'Medium'.
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This zone contains the main interconnected transmission network in South Wales and a large part of the transmission network in Central England. The zone is exporting and has generation sited at Oldbury, Seabank, Aberthaw, Barry, Baglan Bay, Fifoots and Didcot with a substantial amount of generation scheduled in the SYS background to connect at Pembroke. Generally the internal transmission is strong but considering planned generation, local restrictions are likely to apply. Hence, the opportunity for new generation projects within the zone is considered to be 'Medium'.
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This zone covers the Central London area, a heavily importing area with limited generation. The boundary capability proved to be close to the requirements determined by the SYS background for most of the period and insufficient for the last year. At the same time, the probabilistic transfers indicated that some generation is likely to be present during winter peak.
While there is a significant opportunity for generation in this area, the transmission infrastructure within the zone is such that new generation would necessarily need to be sufficiently well spread, and at precise locations, if major transmission reinforcements were to be avoided. If suitable sites could be found opportunities for new generation in these zones would be 'very high'. It is appreciated that siting difficulties and access to existing transmission infrastructure could be problematic, but there would be a great benefit to the system of base load plant in the London zone.
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This zone is encircled by the Thames Estuary boundary and contains the generation on the Thames Estuary and also generation on the Essex and Kent coasts and is an exporting zone. The cross-channel link to RTE feeds into Sellindge and the Britned interconnector is scheduled to connect during the SYS period. Renewable generation is also planned to connect during the period.
Current opportunities for new generation are 'high', but would drop to 'medium' given that the above generation connects within this zone. It should be stressed that opportunities in the Estuary are very sensitive to precise location.
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This is a large importing zone covering the area from Hastings to Southampton on the South Coast and connected to the adjacent zones by five double circuit 400kV lines. According to the SYS background, generation is expected to connect during the period. The opportunity for new generation development can be regarded as 'high', however, the transmission infrastructure could require local reinforcement within this zone for new generation to be accepted.
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This zone is enclosed by the South West boundary and is an importing zone with the only large generation presently being the nuclear plant at Hinkley Point B. In the SYS background, new generation is due to connect in 2007/08 and 2010/11. As in Zone 16, the opportunity for generation development can be regarded as 'very high', although connection of the above generation would drop this to 'high'. However careful consideration would need to be given if too large a development should take place at the far western end of the Peninsula.
This section provides information on possible future opportunities for the provision of voltage support services to the GB transmission system.
Generating units providing a Mandatory Reactive Power Service (i.e. under and in accordance with the requirements of the Grid Code) receive system Ancillary Service Payments according to arrangements set out in Schedule 3 of the Connection and Use of System Code, CUSC. This provides for a Default Payment Mechanism (DPM) and for alternative, bilateral, Market Agreements.
The Schedule also provides for Market Agreements for Enhanced Reactive Power Services from pre-qualified providers (for example, generating units able to provide reactive power capability in excess of the Grid Code requirements).
The terms 'Reactive Power Default Mechanism', 'Obligatory Reactive Power Service', 'Enhanced Reactive Power Service' and 'Market Agreement' are defined in Schedule 3 of the CUSC. The CUSC Schedule 3 also sets out payment rules and qualifications and evaluation criteria. The payment rate under the Reactive Power Default Mechanism is now indexed against RPI and Power Prices, and has varied between £1.75/Mvarh and £3.58/Mvarh during 2005/06.
Table 8.2 gives those network reinforcements that would be required in future to ensure that the system meets Licence Standards for the given SYS background. Amongst these reinforcements are schemes for the support and control of voltages in different parts of the network. As an alternative to purchasing the relevant assets, we would be willing to contract with service providers for voltage support services when this would be economic. As discussed in Additional Works for Licence Compliance the voltage support schemes detailed in Table 8.1 are those required for the specific 'SYS background'. However, as a general guidance it is broadly true that voltage support requirements increase at high levels of power transfer across the system. Thus further reactive compensation schemes over and above those detailed in Table 8.2 could be expected with backgrounds which result in higher transfer levels.
The voltage support schemes included in Table 8.2 are identified in terms of specific types of plant, i.e. mechanically switched capacitors (MSCs) and static var compensators (SVCs), and in terms of defined ratings at identified supergrid substations. However, these schemes must be regarded as indicative only, and the opportunities will, as previously explained, depend on the outturn generation and demand background. We would consider offers of service in the region of the identified sites, different ratings or different performance characteristics. The offered services would be evaluated on a case by case basis, and contracts awarded where they would be economic and enable system needs to be met by the required dates. The types of voltage support service that might be offered and the types of performance that we would seek are discussed later in this section.
One means by which we address the uncertainty in future transmission requirements, is to delay commitment to asset construction to the latest possible date, while at the same time, ensuring that we can provide an efficient, co-ordinated and economic system compliant with the security standards, as required by the Electricity Act 1989 and the Transmission Licence. Similar considerations apply when placing contracts for voltage support services. A contract would be let when we are sufficiently confident that the offer represents an economic, practical and robust means of meeting the system requirements in the context of overall transmission system cost and performance and the surrounding uncertainties. A contract may be valid for one or more years.
The types of services that we believe might be offered include:
(i) generating plant able to offer a greater reactive power range than that specified in the Grid Code and paid for under System Ancillary Service Contracts; and
(ii) synchronous compensation plant, de-clutchable gas turbines or static compensation plant.
However, the above list is illustrative only and any offered service would be considered on its merits.
Contracts would be assessed by comparing the total costs and the performance of alternative options that match the system requirement. Performance factors considered would include rating, speed of response, availability of the service relative to the system requirement and control issues. In the case of additional capability from generating units, the predicted merit order position and running regime of the units would be a critical factor.
Where a contract would involve a new connection to our transmission system (e.g. a service offered under item (ii) above) the cost of the connection would have to be factored into the offered contract price. Before contract terms could be finalised, therefore, a formal application for a connection would need to be submitted in order that we could offer connection terms.
We currently buy equipment of the mechanically switched capacitor (MSC) or static Var compensator (SVC) type specifically for voltage support and these are discussed in the following paragraphs.
Mechanically Switched Capacitors (MSCs)
These provide switchable blocks of susceptance and are used where it is necessary to offset the reactive requirements of the intact system (which change slowly through the day) or to provide a response (after some 30 seconds) following a system contingency such as an outage of transmission equipment or generating unit. MSCs have high year-round availability and reliable performance. They may be operated either by remote control or by automatic control with remote setting of switching criteria.
MSCs would provide the initial basis for contract comparison where the system requirement is to offset slowly varying reactive demands or to provide a slow, infrequent response to system contingencies.
Static Var Compensators (SVCs)
Whilst continuously rated for reactive current within their operating range, these devices are able to adjust their reactive current very quickly (within 100ms) in response to system voltage changes. They are thus used when it is necessary to cope with minute-to-minute changes in reactive requirement, and also rapid changes due, for example, to faults on the system. SVCs have high year-round availability and perform reliably. They operate under automatic control with remote adjustment of control parameters by ourselves.
SVCs would provide the initial basis for contract comparison where the system requirement is to cope with minute-to-minute changes in reactive requirement or to respond rapidly to system contingencies.
All reactive compensation equipment bought by ourselves is specified to be re-locatable to permit redeployment if system needs change in future. Any contract for a reactive service would need to reflect this flexibility through contract duration or re-locatability.
We would welcome offers of voltage support services, subject to provisos that any new equipment connected to the transmission system, including the connection between the equipment and the transmission system, would need to meet (and any existing equipment would need to continue to meet) the relevant commercial and technical standards.
Interested parties considering offering a service are invited to contact the Contracts & Trading Manager, Network Operations, who will provide details of the reactive power market mechanisms and will be happy to discuss possible tenders and contract arrangements, service requirements, locations and performance factors in further detail.
Table 9.3 shows the reactive energy generated by Large Power Stations. This has formed the basis upon which 'reactive energy' payments are made. Data is provided for the period from April 1995 to September 2005 and is the latest information available at the time of writing. Data for Scotland has only been available since 1 April 2005. Accordingly prior to that time information is restricted to the three geographical areas in England and Wales, namely: North; Midlands; and South.
Modified versions of the main system boundaries in England and Wales have been used to define the above three geographical areas (see Figure A.4.3). 'North' is defined as the area north of a boundary, which follows boundary 8 in the west but reverts to boundary 9 east of Ratcliffe on Soar. 'South' is defined as the area south of a boundary which follows boundary 9 in the west but reverts to the section of boundary 14 just south of East Claydon, Sundon and Wymondley and then boundary 15 south of Braintree and north of Rayleigh Main. 'Midlands' is the area bounded by the above two modified boundaries.
The Energy Act (2004) received Royal Ascent in July 2004. Under powers granted by this legislation the Secretary of State directed changes to licences and designated changes to codes that together provided for the introduction of the British Electricity Trading and Transmission Arrangements (BETTA), which were subsequently introduced on 1 April 2005 They replaced the previous New Electricity Trading Arrangements (NETA) in England and Wales, and the separate arrangements that existed in Scotland and the British Grid System Agreement (BGSA). This chapter provides an overview of BETTA and reports on related issues such as governance, institutional and contractual arrangements. The chapter concludes with a generalised summary of some of the main requirements placed upon users in relation to their obligations to become party to the various codes and charges under BETTA.
The new arrangements are based on bilateral trading between generators, suppliers, traders and customers across a series of markets operating on a rolling half-hourly basis. Under these arrangements generators self despatch their plant rather than being centrally despatched by the System Operator. There are three stages to the new wholesale market, plus a new settlement process. These are illustrated in Figure 10.1.
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Participation in the bilateral markets (i.e. the Forward/Futures contract market and the Short-term bilateral markets) and the Balancing Mechanism (i.e. offer/bid submission) is optional. Participation in Settlements is mandatory. In addition, certain categories of generator are required to provide Physical Notifications. The Balancing and Settlement Code (BSC) provides the framework within which participants comply with the Balancing Mechanism and Settlement Process. The BSC is administered by a non-profit making entity called Elexon. Information on Elexon is available from its website: www.elexon.co.uk.
The BSC also specifies the process for modifying the BSC itself. All modifications to the BSC are approved by the Authority (Ofgem) and must, in order to be approved, better facilitate achieving the applicable BSC objectives.
Gate Closure is the point in time when market participants notify the System Operator of their intended final physical position and is set at one hour ahead of real time. In addition no further contract notification can be made to the central settlement systems.
Forwards and Futures Contract Market
The bilateral contracts markets for firm delivery of electricity operate from a year or more ahead of real time (i.e. the actual point in time at which electricity is generated and consumed) typically up to 24 hours ahead of real time. The markets provide the opportunity for a seller (generator) and buyer (supplier) to enter into contracts to deliver/take delivery, on a specified date, of a given quantity of electricity at an agreed price.
The markets are optional with participants having complete freedom to agree contracts of any form. Formal disclosure of price is not required.
The Forwards and Futures Contract Market is intended to reflect electricity trading over extended periods and represents the majority of trading volumes. Although the market operates typically up to a year ahead of real time, trading is possible up to Gate Closure.
Short-term Bilateral Markets (Power Exchanges)
Power Exchanges operate over similar timescales, although trading tends to be concentrated in the last 24 hours.
The markets are in the form of screen-based exchanges where participants trade a series of standardised blocks of electricity (e.g. the delivery of xMWh over a specified period of the next day). Power Exchanges enable sellers (generators) and buyers (suppliers) to fine-tune their rolling half hour trade contract positions as their own demand and supply forecasts become more accurate as real time is approached. The markets are firm bilateral markets and participation is optional. One or more published reference prices are available to reflect trading in the Power Exchanges.
Balancing Mechanism
The Balancing Mechanism operates from Gate Closure through to real time and is managed by National Grid in its role as Great Britain System Operator (GBSO). It exists to ensure that supply and demand can be continuously matched or balanced in real time. The mechanism is operated with the System Operator acting as the sole counter party to all transactions.
Participation in the Balancing Mechanism, which is optional, involves submitting 'offers' (proposed trades to increase generation or decrease demand) and/or 'bids' (proposed trades to decrease generation or increase demand). The mechanism operates on a 'pay as bid' basis.
We purchase offers, bids and other Balancing Services see Balancing Services to match supply and demand, resolve transmission constraints and thereby balance the system. As part of this process we are also required to ensure that the system is run within operational standards and limits (see entry on Licence Standard in References).
Generators and suppliers registered within the Balancing and Settlement Code are bound by the relevant requirements of the Grid Code which includes the arrangements for System Operator to accept Balancing Mechanism bids and offers, for calling off Balancing Services and for dealing with emergencies.
Our previous duty to purchase ancillary services economically and to despatch plant in accordance with a merit order has been replaced by a general duty to operate the transmission system in an efficient, economic and co-ordinated manner through the procurement and utilisation of Balancing Services including Balancing Mechanism bids and offers. Normally our GBSO Incentive Scheme covers this duty, however, for 2006/07 NGET is to have its external system operator costs regulated by Ofgem using their existing powers.
As the market moves towards the Balancing stage, we need to be able to assess the physical position of market participants to ensure security of supply is maintained effectively and efficiently. To this end, all market participants are required to inform us of their net physical flows in both the Forwards and Futures Contract Market and the Power Exchange. Initial Physical Notifications (IPNs) are submitted at 11.00a.m. at the day ahead stage. These are continually updated until Gate Closure when they become the Final Physical Notifications (FPNs).
Imbalances and Settlements
Power flows are metered in real time to determine the actual quantities of electricity produced and consumed at each location. The magnitude of any imbalance between participants' contractual positions (as notified at Gate Closure) including accepted offers and bids, and the actual physical flow is then determined. Imbalance volumes are settled at one of the dual imbalance prices; System Buy Price (SBP) and System Sell Price (SSP). Following the Authority approval of BSC Modification Proposal P194 on 23rd March 2006, the methodology that is used to set the imbalance prices is due to change on 2nd November 2006. To reflect this change the following paragraphs describe the existing arrangements and then the new arrangements that are to be introduced on 2nd November 2006.
Current Imbalance Pricing Arrangements
SBP is the price at which deficits are charged and, when the system is short, reflects the average price at which the system had to buy in order to make good the deficit on behalf of the party (i.e. the average of accepted offers). SSP is the price at which surpluses are charged and, when the system is long, reflects the average price at which the system had to sell in order to dispense with the surplus spill energy (i.e. the average of accepted bids). However, some bids and offers are excluded from the averaging calculations on the basis that they are related to system balancing (e.g. resolving transmission constraints) as opposed to energy balancing trades. In addition, an adjustment to the imbalance prices is made based on any pre-gate closure Balancing Services that we have used for energy balancing. This is known as the Balancing Services Adjustment Data (BSAD). Since the introduction of BSC Modification P78 in March 2003, SBP when the system is long and SSP when the system is short are based upon a forward market price derived from Power Exchange trades.
Imbalance Pricing Arrangements from 2nd November 2006
SBP will continue to be the price at which deficits are charged when the system is short, but it will approximate the marginal price at which the system had to buy in order to make good the deficit on behalf of the party (i.e. an approximation of the marginal price of accepted offers). SSP will similarly continue to be the price at which surpluses are charged when the system is long, but again will approximate the marginal price at which the system had to sell in order to dispense with the surplus spill energy (i.e. an approximation of the marginal price of accepted bids). Imbalance prices will be derived by taking the average cost of the marginal 100MWh of actions that National Grid has taken to resolve the energy imbalance - excluding those "tagged" actions taken for system balancing reasons. This is shown diagrammatically in Figure 10.2.
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Under the revised arrangements the "reverse price" i.e. SBP when the system is long and SSP when the system is short will continue to be based upon a forward market price derived from Power Exchange trades.
Imbalance prices are intended to serve as an incentive for market participants to contract sufficiently ahead of Gate Closure to ensure that their physical positions and their contracted positions are balanced. There is therefore a link between imbalance prices and plant margin in that the incentive on a participant to balance determines the level and value of contracting in the forward markets. This price signals drives plant availability, and in the longer term should sustain investment in new capacity. It is therefore essential that imbalance prices are set to provide the appropriate incentives in this respect. Figure 10.3 provides a simplified example where the metered energy output of a generator exceeds the contracted position.
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There is a positive imbalance volume for which the generator would only be paid at SSP. Under normal circumstances SBP exceeds SSP. Had there been a negative imbalance volume, the system would have bought at SBP to compensate and so the generator would be charged at SBP. The use of dual imbalance prices is intended to provide an incentive for participants to balance their own position as accurately as possible.
Finally, in addition to