powercor reliability investigation final report · 3.3 commercial considerations ... 8.5 design and...

Investigation of

Low Reliability Urban and Rural Feeders

Phase One of Two

Powercor

Prepared for

Office of the Regulator General

Victoria Australia

Document Reference : Powercor Final Report.doc

Report Revision : Final

Prepared by : Geoff Brown, Bob Simpson and Robert Mann

Reviewed by : Ralph Parmella

Approved by : Geoff Brown

Date : 19th September 2000

PB Power Low Reliability Urban and Rural Feeder Investigation - Powercor

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TABLE OF CONTENTS

SECTIONS

1 EXECUTIVE SUMMARY 11.1 Reasons for the investigation..............................................................................................1

1.2 Summary findings of the investigation ................................................................................1

1.3 Principal causes of the reliability problems.........................................................................2

1.4 Reliability improvement .......................................................................................................3

1.5 Achievable reliability levels and the cost of achievement ...................................................6

2 INTRODUCTION 72.2 Drivers for investigation.......................................................................................................7

2.3 Investigation process ..........................................................................................................8

2.4 Report structure.................................................................................................................11

3 SUPPLY RELIABILITY 133.1 Introduction........................................................................................................................13

3.2 Customer complaints ........................................................................................................15

3.3 Commercial considerations...............................................................................................15

3.4 Mandatory requirements ...................................................................................................16

3.5 Factors affecting supply reliability .....................................................................................17

3.6 Reliability performance measures.....................................................................................17

4 POWERCOR DISTRIBUTION NETWORK PERFORMANCE 214.1 Powercor outage data .......................................................................................................21

4.2 Overall network performance............................................................................................22

4.3 Analysis of performance by cause ....................................................................................25

4.4 Analysis of performance by network type .........................................................................26

4.5 Relative performance trends .............................................................................................30

4.6 Investigation of poor feeder reliability................................................................................36

5 SELECTION OF FEEDERS FOR DETAILED INVESTIGATION 395.1 Basis of selection ..............................................................................................................39

5.2 Selecting feeders for investigation ....................................................................................40

5.3 Analysis of outage data for selected feeders ....................................................................41

5.4 Application of the investigation to the rest of the Powercor network ................................43

6 FEEDERS INVESTIGATED 456.1 Field investigation of feeder performance.........................................................................45

6.2 Selected long rural feeders ...............................................................................................45

6.3 Characteristics of short rural feeders selected..................................................................49

6.4 Characteristics of urban feeders selected.........................................................................54

7 ASSET MANAGEMENT 597.1 Principles of asset management.......................................................................................59

7.2 Asset management strategies...........................................................................................61

7.3 Overall expenditure ...........................................................................................................64


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8 DESIGN AND CONSTRUCTION 678.1 Network configuration .......................................................................................................67

8.2 Capital expenditure ...........................................................................................................68

8.3 Network planning ..............................................................................................................69

8.4 Feeder planning ................................................................................................................69

8.5 Design and construction....................................................................................................70

8.6 Feeder component items ..................................................................................................70

8.7 Conclusions.......................................................................................................................77

9 OPERATION AND MAINTENANCE PRACTICES 799.1 Asset maintenance............................................................................................................79

9.2 Maintenance expenditure..................................................................................................82

9.3 Inspections ........................................................................................................................85

9.4 Work management............................................................................................................86

9.5 Field management ............................................................................................................86

9.6 Fault management ............................................................................................................86

9.7 Vegetation management ...................................................................................................88

10 RELIABILITY IMPROVEMENT INITIATIVES 9110.1 Introduction........................................................................................................................91

10.2 OAS data quality ...............................................................................................................92

10.3 Feeder reliability modelling ...............................................................................................94

10.4 Programs for improving reliability......................................................................................95

10.5 Powercor’s supplementary submission...........................................................................100

10.6 Effectiveness and monitoring of reliability improvement initiatives .................................102

11 EFFECTIVENESS OF BUSINESS PROCESSES ON SYSTEM RELIABILITY10511.1 Overall performance........................................................................................................105

11.2 People and processes.....................................................................................................106

11.3 Monitoring and communication .......................................................................................107

11.4 Customer service ............................................................................................................107

12 POTENTIAL RELIABILITY TARGETS 10912.1 Objectives and focus of revisions to reliability targets ....................................................109

12.2 Model of potential reliability improvements of Ballarat North feeder...............................112

12.3 Short term reliability improvements.................................................................................120

12.4 Potential short term improvements .................................................................................121

12.5 Medium term improvements to low reliability feeders. ....................................................121

12.6 Medium term improvement costs & targets for low reliability feeders.............................122

12.7 Long term improvements to low reliability feeders..........................................................124

13 CONCLUSIONS 12513.1 Significance of the issue of low reliability feeders...........................................................125

13.2 Limitations of the data, investigation methodology and findings.....................................125

13.3 Principal causes of outages over the last three years ....................................................126

13.4 Reasons for low reliability ...............................................................................................127

13.5 Prevention and avoidance of the outages.......................................................................129

13.6 Performance improvement of low reliability feeders .......................................................129

13.7 Effect of the regulatory regime........................................................................................130

13.8 Conclusions on Reliability Targets..................................................................................131


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14 RECOMMENDATIONS 13314.1 Powercor .........................................................................................................................133

14.2 The Office........................................................................................................................135

Appendix A. BRIEF RESUMES OF PB POWER STAFF UTILISED IN THIS INVESTIGATION 137

Appendix B. DETAILS OF FEEDER PERFORMANCE 141

Appendix C. FEEDER HISTORICAL PERFORMANCE CATEGORY 167

Appendix D. DETERMINATION OF FEEDER FUNDAMENTAL DESIGN RELIABILITY 181

Appendix E. DOCUMENT LIST 187


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TABLE OF CONTENTSTABLESTable 2.3.1 Key Features of the Feeders Investigated ........................................................................ 11

Table 3.1.1 Powercor Network Statistics.............................................................................................. 14

Table 3.1.2 Comparison of key asset numbers with other Distribution Businesses ............................ 15

Table 3.6.1 Definition of Feeder Types ................................................................................................ 18

Table 3.6.2 Definition of Performance Measures ................................................................................. 20

Table 4.2.1 Powercor Overall System Performance ............................................................................ 22

Table 4.2.2 Powercor Overall System Performance Planned and Unplanned .................................... 23

Table 4.4.1 Normalised Faults per 100km of Line................................................................................ 27

Table 4.5.1 Definition of Feeder Historical Performance Category...................................................... 31

Table 4.5.2 Powercor customers receiving poor or deteriorating service against current standards .. 33

Table 4.5.3 Powercor customers receiving poor or deteriorating service against proposed standard 34

Table 5.2.1 Selected Feeder Historical Performance Category ........................................................... 40

Table 5.2.2 Selected Feeder Performance in 1999.............................................................................. 41

Table 5.3.1 Major Causes of Outages on the Selected Feeders ......................................................... 42

Table 5.4.1 Comparison of All the Selected Feeders with All the Network, 1999 Data ....................... 43

Table 5.4.2 Comparison of Selected Feeders with All Feeders by Type, 1999 Data .......................... 44

Table 7.2.1 Networks Process Streams ............................................................................................... 63

Table 7.3.1 Pricing Submission Overall Expenditure ($ 000's) ............................................................ 64

Table 8.2.1 Pricing Submission Capital Expenditure ($ 000's) ............................................................ 68

Table 8.2.2 Pricing Submission CAPEX for Rural and Urban Feeders ($ 000's)................................. 68

Table 9.2.1 Pricing Submission Maintenance Expenditure ($ 000's) ................................................... 82

Table 9.2.2 Operational Maintenance Costs provided by Powercor ($ 000's) ..................................... 83

Table 9.2.3 Pricing Submission Maintenance Costs per km ($'s) ........................................................ 84

Table 9.2.4 Pricing Submission Maintenance Costs per Customer ($'s) ............................................. 84

Table 9.2.5 HV and LV Maintenance Expensed Costs ($'s) ................................................................ 84

Table 9.2.6 Pricing Submission Maintenance Replacement CAPEX Costs per km ($'s) .................... 85

Table 9.2.7 Pricing Submission Maintenance Replacement CAPEX Costs per Customer ($'s) ......... 85

Table 9.7.1 Total CMOS due to Trees.................................................................................................. 89

Table 9.7.2 CMOS and Incidents as a result of Vegetation ................................................................. 89

Table 10.2.1 Causes of Outages in 1997 and 1999............................................................................. 93

Table 10.2.2 Powercor Comparative Analysis of 1998 and 1999 ........................................................ 94

Table 10.4.1 Expenditure on Improving Reliability ($ 000's) ................................................................ 96

Table 10.4.2 Reliability Resulting from Expenditure............................................................................. 96

Table 10.4.3 Proposed SAIDI Improvements and Associated Costs................................................... 96

Table 10.4.4 Summary of Reliability Improvement Programs ($ 000's) ............................................... 97

Table 10.5.1 Supplementary Submission Reliability Improvement Expenditure ($ 000's)................. 101

Table 12.2.1 Causes of Outages on BAN008 .................................................................................... 113

Table 12.2.2 Changes in Reliability with Various Improvments to Feeder BGE024 .......................... 118

Table 12.2.3 Economic Effects of the Reliability Improvement Options Considered ......................... 119

Table 12.5.1 Summary of Potential Means to Improve Medium Term Reliability .............................. 122

Table 12.6.1 Feeder Performance Relative to Average Feeder ........................................................ 123

Table 12.6.2 Cost of Implementing Feeder Reliability Limits ............................................................. 123


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TABLE OF CONTENTS

FIGURESFigure 2.2.1 Quality and Reliability of Supply Complaints per 1000 Customers.................................... 7

Figure 2.3.1 Representation of Powercor Distribution Network ............................................................. 8

Figure 2.3.2 Investigation Process ......................................................................................................... 9

Figure 3.6.1 The Effect of Distribution Network Faults on Performance Measures ............................ 19

Figure 4.2.1 SAIDI SAIFI and CAIDI Trends ........................................................................................ 22

Figure 4.2.2 Average Duration of Faults.............................................................................................. 23

Figure 4.2.3 Average Duration of a Fault by Month ............................................................................. 23

Figure 4.2.4 Fault Rate on HV Feeders................................................................................................ 25

Figure 4.3.1 Causes of Powercor System Outage Minutes for 1997 to 1999...................................... 25

Figure 4.4.1 Causes of Zone Substation and Sub Transmission Outages ......................................... 28

Figure 4.4.2 1999 Long rural CMOS by Cause .................................................................................... 28

Figure 4.4.3 1999 Long Rural by Number of Interruptions ................................................................... 29

Figure 4.4.4 Short Rural Number of Interruptions by Cause................................................................ 29

Figure 4.4.5 Average Duration of a Fault for Urban and Rural Feeders .............................................. 30

Figure 4.4.6 Urban Feeders Interruptions by Cause ............................................................................ 30

Figure 4.5.1 1999 Reliability Relative to Distribution Code Standard .................................................. 32

Figure 4.5.2 1997 Reliability Relative to Distribution Code Standard .................................................. 32

Figure 4.5.3 Low Reliability Relative to the PB Power Benchmarks in 1997 and 1999 ....................... 35

Figure 4.5.4 1997 and 1999 Reliability Relative to the Average for the Year ...................................... 36

Figure 4.5.5 Low Reliability Relative to the Average Feeder Reliability............................................... 36

Figure 7.1.1 Asset Management Linkages........................................................................................... 60

Figure 7.1.2 HSM002 Load Profile ...................................................................................................... 61

Figure 7.2.1 Relationships between Business Streams....................................................................... 63

Figure 7.3.1 Overall Expenditure/km by Feeder Type.......................................................................... 64

Figure 7.3.2 Overall Expenditure/Customer by Feeder Type............................................................... 65

Figure 8.6.1 Lightning Arrestor Correctly Installed on a Transformer .................................................. 71

Figure 8.6.2 Bird Covers Fitted to a Steel Crossarm............................................................................ 71

Figure 8.6.3 SWER ACR Fitted to a Tee-Off SWER Line .................................................................... 72

Figure 8.6.4 Expulsion Drop Out Fuse on a Tee-off Connection ......................................................... 72

Figure 8.6.5 Old Style and Modern Cruciform Construction................................................................. 73

Figure 8.6.6 Excessive Equipment Attached to Recloser .................................................................... 73

Figure 8.6.7 Details of Excessive Equipment attached to a Recloser.................................................. 74

Figure 10.6.1 Change in SAIDI against Maintenance CAPEX Replacement..................................... 102

Figure 10.6.2 Change in SAIDI against Maintenance CAPEX with Reduced Scale.......................... 103

Figure 12.1.1 Customer Minutes Off Supply Relative to the Average................................................ 111

Figure 12.2.1 Base reliability model of long rural feeder BAN008 ..................................................... 114

Figure 12.2.2 Reliability Model of BAN008 - Option of Auto Reclosers and Remote ControlledSwitches Fitted ................................................................................................................................... 115Figure 12.2.3 Reliability Model of BAN008 - Additional Tie Lines Installed ....................................... 116

Figure 12.2.4 Reliability Model of BAN008 - Additional Tie Lines Plus Auto Reclosers and RemoteControlled Switches Fitted.................................................................................................................. 117


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1 EXECUTIVE SUMMARY

1.1 REASONS FOR THE INVESTIGATION

1.1.1 This investigation was initiated by the Office of the Regulator General (the Office) inresponse to an apparent decline in reliability of supply in parts of the provincial and ruralelectricity distribution networks in Victoria contrary to a general trend towards improvedreliability across the State.

1.1.2 In 1995 Powercor Australia purchased the distribution network serving the western sideof the State of Victoria. Similarly TXU Australia purchased and subsequently operatesthe network serving the eastern side of the State. By early in the year 2000 it wasapparent that the number of customer complaints with regard to the level of serviceprovided by Powercor were becoming significant. It was also apparent that the trends inunplanned interruptions to supply delivered by TXU in particular were showing noimprovement. Both companies had a number of areas where the reliability of supplyremained poor as evidenced by the large number of interruptions occurring and the totaltime customers were without electricity. Consequently this investigation of specific partsof the Powercor and TXU networks was initiated by the Office and undertaken on itsbehalf by PB Power. Through media reports and complaints, the Office has becomeaware of a perception that reliability of electricity supply is declining in parts of the state.This report takes into account these perceptions as well as data supplied by Powercor.

1.1.3 The investigation through detailed analysis of fault records, interviews and site visitsfocused on: -

• The nature and causes of the performance of the network at nominated zonesubstations where the history of performance has been poor

• The distribution business network maintenance policies, strategies and plans andthe implementation, execution and monitoring of those strategies and plans

• The business strategies and plans for investment in and upgrading of thenominated zone substations and related infrastructure

• The expected incremental costs that would be associated with any revisions tostandards, codes or licence conditions to address identified network problems

1.1.4 This report covers the investigation of Powercor. The investigation of TXU is reportedseparately.

1.2 SUMMARY FINDINGS OF THE INVESTIGATION

1.2.1 Powercor customers have encountered a wide range of levels of service. Somecustomers in 1999 suffered no interruptions to their supply of electricity whilst othersencountered more than 15 interruptions and others interruptions totalling more than1,500 minutes without supply. Since these are whole feeder averages (and manymomentary interruptions are not recorded) some customers will actually be suffering agreater number of interruptions than can be estimated on the basis of Powercor’sinterruption records.

1.2.2 Powercor has met its regulatory requirements as set out in the Electricity DistributionCode. Although customer expectations vary it is clear from the level of customercomplaints and from media reports that those supplied by feeders with low reliabilityconsider the level of reliability to be unsatisfactory.


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1.2.3 The reticulation installed by the State Electricity Corporation (SEC), whilst adequate atthe time, was never designed to provide the level of service sought by customers today.Furthermore the original network did not allow for the environmental differencesexperienced in different parts of Powercor’s area.

1.2.4 Nevertheless, further actions can be taken by Powercor to improve its overall reliability ofsupply and particularly the quality of supply to customers connected to poorly performingparts of the network. These actions are discussed later in this Section.

1.2.5 The current provisions of the Electricity Distribution Code1, which require the distributionbusinesses to achieve minimum standards of reliability averaged over all rural and allurban feeders, do not encourage the achievement of improved levels of service to adistributor’s worst served customers. Furthermore the limits set out in the Code are nolonger appropriate and have been well exceeded by all five Victorian distributorsalthough they represented a challenge when first introduced. Powercor has initiated anumber of reliability improvement strategies since 1995.

1.2.6 The Office should consider imposing regulatory limits on feeder reliability. One approachwould be to set a limit on the reliability of supply provided to the average customerconnected to the poorest performing feeder relative to the average performanceachieved by that type of feeder in the Powercor distribution network. A possible limitwould be two point one times the average reliability performance on all feeder types.This would improve the reliability to the poorest served ten percent of Powercorcustomers.

1.3 PRINCIPAL CAUSES OF THE RELIABILITY PROBLEMS

1.3.1 Faults on the 22,000 volt (22kV) distribution system cause 85% of all customer minutesoff supply. Although faults at zone substations and on sub transmission circuits impact alarge number of customers they only account for 13% of customer minutes off supply.The low voltage reticulation to a consumer’s property accounts for only 1% of customerminutes off supply.

1.3.2 This investigation developed an understanding of the underlying causes of theinterruptions to supply on the Powercor network by examining all interruptions to a validselection of good and poorly performing feeders of each type. The data relating tointerruptions to supply including fault causes, up to December 1999, had limitations dueto inaccuracies. Discussions with fault staff indicated that the data on fault causes is notas accurate as Powercor management believes it to be. An improved system foraccurately capturing the causes of faults is urgently required.

1.3.3 Approximately seventy percent of all outages are avoidable or are controllable byPowercor. Thirty percent are considered as being beyond Powercor’s immediate control(trees, lightning, weather, vandalism, cars hitting poles and some of the instances of “noidentified cause”. It is possible further action by Powercor could prove to be a mitigatingfactor in around seventy percent of faults.

1.3.4 The top four causes of outages account for 61% of all outages (Unknown or Other, 21%,Planned Outages 16%, Malfunction 13% and Lightning 11%). Electrical overload,pollution and birds each account for around 4%.

1.3.5 Malfunction and lightning were the major causes of faults on the selected feeders. Theother fault causes on the feeders studied varied from year to year indicating it can bedifficult for Powercor to target specific causes and so reduce the interruption frequency.

1.3.6 The cause of faults categorised as “malfunction” is not clear. Generally it is anoperational problem with an equipment item such as a circuit breaker but it can also be a

1 Electricity Distribution Code April 1999


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protection problem. Powercor is reviewing its feeder protection policies in order toreduce “malfunctions” but it is not clear that protection problems are always the cause.

1.3.7 Twenty one percent of customer minutes off supply result from incidents categorised as“unknown” or “other” for which no known cause is located. These are generally transientfaults. This indicates a significant potential to improve reliability through increasing useof reclosers and also by better management of faults after they occur.

1.3.8 Planned outages accounted for 20% of all customer minutes off supply in 1999 and 16%over the whole period investigated. While the total impact of planned outages is nowless than earlier years, it is still 30% greater than TXU. Powercor could, with someinnovation, reduce its planned SAIDI without limiting the level of maintenance andreliability improvement work it undertakes through the extension of live line maintenancework. The utilisation of small generators to provide a supply during off load maintenanceand the installation of additional interconnections between feeders would also help.

1.4 RELIABILITY IMPROVEMENT

Management Issues

1.4.1 Powercor should prepare an integrated asset management plan that provides acomprehensive overview of the condition of network assets, specifies reliability, securityand availability targets, identifies plans and budgets for network development, assetreplacement and reliability improvement. This plan should be updated at least annually.

1.4.2 Reliability of supply needs to be given a much higher profile within the organisation.Initiatives such as the issuing of regular reports on supply reliability to a wide range ofstaff at all levels and the training of field staff in the importance of accurately recordingthe cause of faults in the Outage Management System could assist in the achievement ofsuch an objective.

Powercor are of the opinion that “Reliability of supply is given a very high profile within thebusiness and both senior management and employees are well aware of reliability of supplymatters and initiatives.”

1.4.3 Powercor recently restructured from a geographic approach to network management intoa process approach, whereby a single group is responsible for a particular processacross the whole Powercor network. A reason for introducing this approach was todevelop a more consistent approach to investment decision making. Since it is notpossible for a single localised group to know the complete network intimately, decisionmaking is becoming increasingly reliant on information derived from IT systems.However, the information coming out from an IT system is dependent on the accuracy ofthe data fed in, and in the case of the outage management system, this is often less thanaccurate. Each feeder or part of a network is unique, and decisions on the expenditureon reliability improvement would be improved if they utilised more local input fromregional staff.

1.4.4 The accuracy of the information on fault causes in the outage management system maybe limiting the effectiveness of expenditure on reliability improvement. Powercor needsreview the range of fault causes that are available and develop a process that ensuresthat the recording of fault causes is more consistent. This is likely to mean that writtenguidelines should be prepared and that training should be given to both field staff andfault dispatchers.

1.4.5 It is possible to make meaningful reductions in the number of interruptions by targetedimprovements designed to reduce the frequency of certain fault causes in areas wherethese have proven to be particular problems. Powercor has developed a model that isused as the basis for targeting reliability improvement expenditure. The model selectsfeeders to be targeted on the basis of the previous year’s customer minutes off supplyand improvement measures are determined by fault causes as recorded in the outage


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management system. The model would be more robust if feeder performance over aperiod of more than one year was assessed. Furthermore, the information on faultcauses, as recorded in the outage management system, may not be sufficiently accurateto be used as a basis for determining the most effective corrective action. Reliabilityimprovement expenditure could be better utilised if this model was more robust.

1.4.6 There is a need for more detailed investigation of high impact faults when the cause of afault is not obvious or when it appears that critical equipment did not operate efficiently.This investigation needs to be timely and the accountability for ensuring that follow upaction needs to be clearly defined. Examples of incorrectly recorded outages wereapparent during this investigation.

Reducing the Number of Outages Occurring

1.4.7 It should be possible to reduce the number of interruptions occurring in the short term onsome low reliability feeders. This could be achieved through the following means: -

l Investigating and analysing the causes of equipment malfunction and takingpreventative action to address recurring problems. The causes of malfunctionwere not evident from the outage information data and the issuing of regular faultreports would increase awareness of these problems. Powercor is addressingequipment malfunctions by reviewing protection practices. This investigationhowever was unable to obtain sufficient information to determine whether this wasan effective response. It may be that a malfunction merely indicates that the faultcrew do not understand why a particular event occurred, and therefore assume,erroneously, that an equipment item did not operate as designed.

l The installation of modern surge arrestors in areas likes Terang that are prone tosevere lightning storms. Current policy is not to put surge arrestors on smalltransformers for economic reasons. There may however be a case for installingsurge arrestors at all distribution substations in areas particularly prone to lightningand where power outages can be particularly disruptive to customers.

l The replacement of the old SEC standard pole top structures using brown pininsulators with an upgraded design, particularly in area prone to pole top fires.There is a significant variation is the extent to which this has been done across thenetwork, reflecting different priorities in different areas under the old geographicorganisation structure. For example, the investigation noted that suchreplacement was complete in Ballarat but little progress had been made inGeelong. Furthermore, structures with old style pin insulators were noted incoastal locations. The new process organisation should ensure a more consistentand balanced approach. Powercor has now initiated a major replacementprogramme in the Geelong area, in response to the spate of pole top fires thatoccurred earlier this year.

l The insulation of substations in areas prone to bird and animal faults. In 1999,birds and animals together caused 20% of the interruptions on long rural feeders.

1.4.8 Electrical overload, particularly of transformers, is reported as a significant cause ofoutages. However it is not clear how accurate this information is since it is difficult forfault staff in the field to determine accurately the cause of a blown fuse. Without moreinvestigation on it is difficult to know how Powercor should best target overload problems.Low voltage, due to saturation of the transformer core is usually an early indication oftransformer overload and it may be that a better strategy for identifying and addressingvoltage problems is required. However, electrical overloads can occur due to customersnot advising Powercor of load increases, but there is little indication that customer drivenissues are causing significant reliability problems. Nevertheless, as electrical overload isreported as a significant cause of low reliability Powercor should be investigating theissue to a greater extent than is currently being undertaken.


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1.4.9 Powercor should review its policy in relation to he high voltage fusing of distributiontransformers. Fuses should be designed to protect against faults rather than overloads.This may require higher rated fuses than currently used to protect small transformers,which may prevent nuisance trippings caused by spikes and surges.

1.4.10 While vegetation control is not the significant issue for Powercor that it is with TXU, thereis nevertheless a problem in declared non-fire risk areas where tree cutting on publicroads is the responsibility of local councils. Powercor should work more closely withcouncil staff to develop an improved standard of vegetation control in these areas.

Reducing the Number of Customers Affected by the Outages Occurring

1.4.11 Powercor should continue its programme of installing reclosers on the backbone of ruralfeeders. With electronic protection, up to two reclosers can be installed in series along afeeder, reducing the number of customers affected by many outages. In country areasthere is a case for installing a recloser between the rural and urban section of a feeder sothat urban customers are not impacted by faults in rural areas.

It is important that protection discriminates correctly so that faults do not impact morecustomers than necessary. If protection does not operate as designed supply restorationcan be delayed, as a fault crew may start looking for the fault in the wrong place. Whena fault occurs and it appears that protection has not operated correctly, an engineeringinvestigation should be undertaken and appropriate remedial action implemented.

Reducing the Duration of Outages

1.4.12 Significant improvements could be achieved by accelerating the installation of remotecontrol on the network. Currently over 36% of substations do not full remote control andthe installation of remote control is programmed to extend through to 2005. Remotecontrol can speed up fault location and reduce the duration of feeder faults. Powercorwould seem to have less enthusiasm for remote control than other distributors, in spite ofthe large geographic area that it covers.

1.4.13 The installation of more remote controlled switching devices throughout the networkwould also reduce outage times, particularly on urban and some short rural feeders byenabling customers beyond a fault to be readily backfed using alternative supplies fromother feeders. It is now possible to buy remote control switches with inbuilt remote readfault locators. The use of such devices should be considered as they could allow theswitching zone in which a fault is located to be identified remotely. This allows supply tobe restored to unaffected customers while the fault crews are travelling to the fault. Suchtechnology has the potential to significantly reduce outage times in areas like Sunshinewhere there is a high level of connectivity with adjacent feeders and fault crews can takesome time to reach the fault location.

1.4.14 Powercor’s response to feeder faults can be inefficient. Current OCEI guidelines relatingto the action to be taken following a feeder fault are unclear as to who is responsible,should an attempted reclosure cause an injury. As a result some operators prefer topatrol a feeder before re-energising the line. The guidelines allow a reclosure to beattempted 15 minutes after a fault occurs. In rural areas, a reclosure should always beattempted before patrolling a feeder unless the controller has good reason to believethat, this might cause a hazard. The OCEI guidelines should be revised to make it clearthat a controller cannot be held responsible provided the defined procedure is followed.

1.4.15 Powercor should have documented feeder specific, supply restoration plans for feederswhere experience has shown that it can be difficult to locate a fault or restore supply.

1.4.16 Powercor should review the number and location of fault response crews across itsnetwork as outage durations are often extended by long fault response times. Thisapplies not only to rural areas but also to urban areas such as Sunshine. The use ofLocal Service Agents is a good initiative but there are indications that this programmecould be more effective.


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Incentives and Experience to Improve Performance

1.4.17 Powercor responds to regulatory messages and its prioritisation of capital investment isinfluenced by the need to improve performance to customers on average. There is alack of focus on the quality of supply to the worst served customers, partly because ofdifficulties in measuring reliability of supply at as customer level. Powercor should startto measure supply reliability at distribution substation level in order to determine thelocations of the worst served customers across its network.

1.4.18 The Office’s current reporting requirements focus on feeder performance but within eachfeeder there is a range of performances being suffered by customers. Some currentlyreceive a level of reliability more than three times worse than the reported feederaverage reliability. Conversely some receive a level of reliability significantly better thanaverage. The reporting regime should be revised to require the reporting of reliability onthe basis of the reliability of supply to individual customers. The systems and processesto implement this are achievable and not excessively costly.

1.4.19 The Office should consider introducing a reporting system modelled on the National Faultinformation Reporting System (NAFIRS) used in the UK. The reporting of fault causes,using common definitions and standards, would provide a better understanding of thedifferences between the various networks, and would also permit the effectiveness ofdistributors’ reliability improvement programmes to be independently evaluated.

1.4.20 The Office should consider requiring all the Victorian Distribution Businesses to publishan Asset Management Plan including a quality and reliability of supply statement settingout the service delivered by the DB’s and their plans for improving it. Publication ofthese plans would permit the direct comparison of the businesses and raise publicawareness to the actions planned by the companies to raise the reliability of supply totheir customers. Increased scrutiny of distributors’ asset management practices shouldimprove the effective of asset management in the medium term.

1.5 ACHIEVABLE RELIABILITY LEVELS AND THE COST OF ACHIEVEMENT

1.5.1 There is currently no requirement to improve low reliability feeders. The DistributionCode sets only a minimum average standard that is easily achievable. This reportdemonstrates there are wide ranges of performance and, at a relatively low cost therange can be reduced. The measures set out in the Draft Decision (Minimum ServiceLevels and reliability adjustments to the tariff should be utilised and evaluated first and ifthese are not successful changes to the Distribution Code should be considered. Anyrevision to the Distribution Code should include a provision to ensure that no feeder hasa level of reliability more than 2.1 times worse than the average for that type of feeder.This would improve the reliability of supply to ten percent of Powercor’s customers.

1.5.2 Four alternative methods of achieving an improvement in reliability were investigated.Detailed reliability modelling of the long rural feeder BAN008 utilising the actual outagedata of this feeder determined that all four improvements (additional ties to other feeders,improved maintenance, reductions in the outage times and the use of more automation)would be cost-effective. The measures proposed would reduce the customer minutes offsupply on the feeder by up to 44% and if logical combinations of the four wereundertaken an improvement of up to 74% could be achieved. Powercor has alreadyidentified and implemented some of these measures.

1.5.3 An eleven percent reduction in the customer minutes off supply for the whole Powercordistribution network is achieved if the proposed improvements are made to all feederswith a reliability of more than 2.1 times poorer than the average. The cost ofimplementing these improvements is estimated at $22.1m. Powercor’s EnhancedReliability Case submission to the Office during the Electricity Price DeterminationReview indicated that $31m is required to achieve a 14% overall improvement in SAIDI,which equates to a cost of $24.5m to achieve an 11% improvement, slightly in excess ofthe $22.1m determined by this investigation.


Doc No.71321 19/09/00 Page 7

2 INTRODUCTION

2.1.1 The Office of the Regulator General (the Office) initiated this investigation because of anapparent decline in reliability of supply of parts of the provincial and rural electricitydistribution networks in Victoria contrary to the general trend towards improved reliabilityacross Victoria.

2.1.2 Other regulators, it is understood, have not investigated low supply reliability to the samedepth as has been carried out for this report. However, other countries (eg. Argentinaand the UK) have a more intrusive approach to regulation.

2.1.3 Clear indications of possible declines in supply reliability were not evident in the dataprovided to the Office by the Distributions Businesses (DBs) for year ending December1998. The results for the year ending December 1999 show some deterioration inperformance in particular areas and continuing poor performance in other areas.

2.1.4 PB Power was appointed by the Office to carry out this investigation which focused on: -

• The nature and causes of the performance of the network at nominated zonesubstations where the history of performance has been poor

• The distribution business network maintenance policies, strategies and plans andthe implementation, execution and monitoring of those strategies and plans

• The business strategies and plans for investment in and upgrading of thenominated zone substations and related infrastructure

• The expected incremental costs that would be associated with any revisions tostandards, codes or licence conditions to address identified network problems

2.2 DRIVERS FOR INVESTIGATION

2.2.1 Customer complaint statistics as shown in Figure 2.2.12 and other sources such theEnergy Industry Ombudsman, the Office of the Chief Electrical Inspector, newspaperclippings, customer and interest groups have also indicated concern regarding reliabilityof supply. These concerns, whilst qualitative in nature, together with analytical resultswere such that the Office considered that in depth investigations of both TXU andPowercor would be required. This report covers the investigation into the performance ofPowercor.

Figure 2.2.1 Quality and Reliability of Supply Complaints per 1000 Customers

0.0

0.5

1.0

1.5

2.0

2.5

1997 1998 1999

Co

mp

lain

ts p

er 1

000

cust

om

ers

Powercor

United Energy

TXU

CitiPowerAGL

Source: The Office Annual Statistics

2 The Office annual statistics


Doc No.71321 19/09/00 Page 8

2.3 INVESTIGATION PROCESS

2.3.1 Powercor’s network consists of a 66 kV subtransmission network that takes power fromGPU terminal stations to a series of zone substations. Each of these zone substationshas a number of feeders operating usually at 22 kV that feed out into the community. Atvarious points distribution transformers are connected to these feeders to supplyindividual or groups of consumers. The reliability of supply to end consumers is mainlyaffected by the performance of the feeders connected to each zone substation. The keyfeatures of the distribution network are shown in Figure 2.3.1 below.

Figure 2.3.1 Representation of Powercor Distribution Network

Low voltage supplyto customer

66kV Sub TransmissionInterconnection to other

Zone Substations

ZoneSubstation Supply to customers on Urban

Feeders

Average 1,465 customers per feeder

Average load 7 MVA per feeder

Average length 12 km

Average 1999 SAIDI 146 minutes

Average 1999 SAIFI 1.98

Alternative LV and HV suppliesavailable for most customers

Alternative HV supply

Supply fromGPU

Alternative LV supply

Supply to customers onShort Rural Feeders






Limited if any alternative HV suppliesand only a few alternative LV suppliesavailable

Supply to customers onLong Rural Feeders






Alternative HV supplies and LVsupplies are rare

Long radial lines and SWER systemssupply remote customers

22kV

Lon

g R

ural

Fee

der

22kV

Sho

rt R

ural

Fee

der 22

kV U

rban

Fee

der

sSub transmission systemFaults represent only 13% of totalcustomer minutes off supply

Transmission and GenerationFailures extremely rare


Doc No.71321 19/09/00 Page 9

Figure 2.3.2 Investigation Process

Feeder outageanalysis

Identify theactual

nature of andwhere

differences inreliability are

occurring

� Select feeders forinvestigation

Detailed feederanalysis

Identify whatare the realproblems on

selectedfeeders

Review relevantbusiness processes

Identify whythere areproblems

on selectedfeeders

Review withOffice

Draft reportto the

Office andDistributionCompany

Office Data

DistributionCompany

Data

� OAS information� Performance

history

Analysis

� Asset history and condition� Feeder configuration� Feeder design and standards� Maintenance and operational

information� Asset Management strategies� Investment strategies and plans� Detailed interviews in field and

HO

Identifypotentialreliabilitytargets

Consultation

Releasefinal report

Stage One Stages Two and Three

Feeder Reliability and Expenditure Investigation


Doc No.71321 19/09/00 Page 10

2.3.2 The flow chart shown in Figure 2.3.2 describes the approach adopted in carrying out theinvestigation. The process consisted of a series of stages, commencing with analysis offeeder outages and the selection of feeders for detailed analysis. The problems with theselected feeders are considered in detail to establish what are the real problems.Potential reliability targets were also identified.

2.3.3 Outage statistics were obtained from Powercor as the base data. Extensive analysis ofthe nature, location and the underlying causes of poor performance was undertaken as apart of this investigation. Initially, it was intended to examine the performance of feedersat two zone substations. After carrying out the initial analysis, it was recognised thatselecting eleven feeders over a range of locations would result in a better understandingof the reliability issues with the Powercor network.

2.3.4 The eleven selected feeders and their performance are set out in Table 2.3.1. PBPower, in the initial stages of the 2001 to 2005 Electricity Price Determination Reviewsuggested for Powercor total System Average Interruption Index (SAIDI) target figures of315.6 minutes for Long Rural, 177.6 minutes for Short Rural and 130 minutes for Urbanfeeders. Appendices A and B indicate the overall performance of the feeder for each ofthe last three years and its performance relative to the PB Power target SAIDI.

2.3.5 Once the feeders had been selected, Powercor was asked to supply documents relevantto the investigation, including: -

• Asset management strategies and plans covering enhancement, replacement,refurbishment and maintenance

• Investment strategies

• Network design standards

• Maintenance standards including inspection policy

• Vegetation management policy including fire mitigation plan

• Process for operating, fault handling and restoration

2.3.6 Structured interviews were conducted with the Network Manager, Planning,Maintenance, Operations and Fault staff, Field Supervisors and Inspectors, and staff whocarry out restoration and remedial work on the factors affecting reliability of the selectedfeeders and the underlying causes. Significant parts of the feeders were visited.

2.3.7 PB Power selected internationally recognised personnel3 with relevant experience in theasset management of network businesses to carry out this investigation. PB Power haspreviously carried out regulatory technical audits of Victorian DBs, has been extensivelyinvolved in the review of the Y2K preparedness of the Victorian electricity industry andcarried out the capital expenditure and reliability analysis for the offices 2001 distributionprice review. In the United Kingdom, PB Power has also been a principal adviser toOfgem for distribution business monitoring and reform and for many of the DBs.

3 Brief Resumes of the personnel involved in this investigation is included in Appendix A


Doc No.71321 19/09/00 Page 11

Table 2.3.1 Key Features of the Feeders Investigated

SAIDI5 (minutes)& SAIFI

Feeder ID Feedertype

Number ofcustomers4

1997 1998 1999

Performancesummary& 1999 SAIDI vsbenchmark

Terang

TRG005

Longrural

1,235 429

3.4

256

2.4

1,974

12.2

Poor

6.3 x benchmark

Ballarat North

BAN008

Longrural

4,164 680

6.4

357

5.4

1206

8.5

Poor

3.8 x benchmark

Horsham

HMS002

Longrural

2,928 659

5.3

1,155

12.3

246

3.2

Improved

0.8 x benchmark

Woodend

WND012

Shortrural

986 88

1.7

413

4.2

1,185

11.0

Deteriorated

6.7 x benchmark

Terang

TRG001

Shortrural

429 998

5.9

321

1.8

667

3.6

Poor

3.8 x benchmark

Shepparton

STN003

Shortrural

782 64

0.6

267

2.8

695

4.4

Poor

3.9 x benchmark

Waurm Ponds

WPD014

Shortrural

3,030 142

1.7

501

7.5

229

3.3

Det/improved

1.3 x benchmark

Ballarat North

BAN015

Shortrural

3,492 72

1.4

365

6.9

74

1.2

Good

0.4 x benchmark

Sunshine

SU005

Urban 514 651

8.7

1,018

20.2

857

10.7

Poor

6.6 x benchmark

Geelong

GL022

Urban 3,468 33

0.3

79

0.7

275

3.1

Poor

2.1 x benchmark

Sunshine

SU004

Urban 497 205

2.6

62

0.4

93

0.8

Good

0.7 x benchmark

Note the values shown in this table include the effect of zone substation and sub transmission system outages

2.4 REPORT STRUCTURE

2.4.1 This report examines the performance of Powercor’s network covering supply reliabilityand network performance. The selection of the feeders for detailed investigation is thencovered together with a summary of the feeders investigated. Asset managementstrategies, plans and programs are reviewed including design and construction factorsand operation and maintenance practices.

2.4.2 The effectiveness of reliability improvement initiatives and business processes are thenconsidered. Based on detailed modelling of a particular feeder, potential reliabilitytargets are presented followed by conclusions and a series of recommendations.

4 Number of customers served by the feeder at the 1999 year end.5 Section 3.6 of this report includes a detailed explanation of the measures SAIDI and SAIFI


Doc No.71321 19/09/00 Page 13

3 SUPPLY RELIABILITY

KEY POINTS

Most reliability problems are within the Powercor network. As expected, Powercorcustomers are affected more by outages associated with the distribution network ownedand operated by Powercor, than outages in the transmission or generation systems dueto the differing design standards that are economically viable.

Section 3.3

Customer reliability expectations and the network capability are potentiallymismatched. Anecdotally, customers are indicating that they require higher levels ofreliability than the network was designed for when it was installed several decades ago.

Section 3.2

A balance of expenditure is required. Satisfying increasing customer expectationsrequires a balance of short-term improvements in maintenance practices or increasedmaintenance expenditure and increases in long term reconfiguration expenditure.

Section 3.3

3.1 INTRODUCTION

3.1.1 In the State of Victoria, the distribution of electricity is undertaken by five shareholderowned companies that operate both a partially contestable retail business for the sale ofenergy to consumers and a monopoly business over defined areas for the distribution ofelectricity. Whilst they may share a number of common resources within the DistributionBusiness, and are inextricably linked together in many consumers minds, thisinvestigation is only associated with the physical network for the distribution toconsumers of electricity from the extra high voltage terminal stations of the grid network.

3.1.2 Powercor own and operate the distribution network serving the western side of the state.The Transmission Company, GPU, transmits power at extra high voltage from generatingplants to the 11 terminal stations at which electricity is supplied to Powercor. Powercorutilises over 100-sub transmission 66 kV lines to distribute power from the terminalstations to 66 zone substations. At the zone substations the electricity is transformeddown to 22 kV and distributed on towards customers at this lower voltage by overheadand underground feeders. In most cases, a final transformation of the voltage down to240 or 415 volts occurs near the consumer’s premises.

3.1.3 Most of the electricity distribution assets in use in Victoria today were constructed by theState Electricity Corporation of Victoria (SECV) and therefore the design andconstruction is largely similar across all the Distribution Businesses. There are howeverpotentially significant differences in the business organisation, management and culturebetween Powercor and the other Distribution Businesses resulting in differences in thequantity and effectiveness of asset maintenance, replacement and developmentexpenditure.

3.1.4 The essential features of the business are set out in Table 3.1.1 which providesinformation on Powercor network statistics projected for 2001 based on the PowercorPricing Submission6 and the UMS Operating Expenditure Bench Marking Study7

6 Powercor 2001 Electricity Distribution Price Review Submission7 Operating Expenditure Benchmarking Study carried out by UMS for the Office


Doc No.71321 19/09/00 Page 14

Table 3.1.1 Powercor Network Statistics

Total number of customers served 573,885

Equipment used to provide this service

Sub transmission zone substations 66

Distribution feeders 321

Distribution substations 67,350

Sub transmission lines

Overhead 3,106 km

Underground 0 km

Total 3,106 km

Urban lines

Overhead (HV) 1,674 km

Underground (HV) 46 km

Total (HV) 1,720 km

Overhead (LV) 6,579 km

Underground (LV) 3,566 km

Total (LV) 10,145 km

Rural short lines

HV 7,966 km

LV 8,081 km

Rural long lines

HV 46,200 km

LV 5,091 km

3.1.5 The key statistics in Table 3.1.1 reveal a number of parameters that will affect thereliability achieved and the expenditure required for operating and maintaining thePowercor network. The Powercor high voltage distribution network is comprised ofnearly 56,000 km of High voltage lines of which only 46 km (0.08%) is underground.Underground systems in general provide a higher level of reliability with fewer faultsoccurring. The faults on underground systems take longer to repair than on overheadsystems but this is usually mitigated by the availability of alternative supplies to mostcustomers, another feature of underground systems.

3.1.6 Powercor has 97% of its overhead lines supplying rural areas with a total of only 1,720km of high voltage lines supplying urban areas. Powercor asset management strategieswill therefore be focussed on rural distribution networks and the issues that result fromthe nature of the locations served. The Powercor Electricity Distribution Price ReviewSubmission makes some pertinent comparisons between the network operated byPowercor and the other Distribution Businesses. These are reproduced in Table 3.1.2.The data presented here takes no account of the external environment which influencesthe reliability of supply and varies greatly between the areas served by the different DB’s.As Powercor has the smallest number of customers per pole and per total line km it couldbe anticipated that Powercor customers would receive a service reliability lower than thatprovided by other DB’s. The low number of Powercor customers per distribution and perzone sub station are mitigating factors that render these statistics a poor guide toexpected or acceptable reliability.

POWER


Doc No.71321 19/09/00 Page 15

Table 3.1.2 Comparison of key asset numbers with other Distribution Businesses

Number of Customers Per Asset : -

Company

Per

pol

e

Per

tota

llin

e km

Per

over

head

line

km

Per

und

er-

grou

nd li

nekm

Per

zon

esu

bsta

tion

Per

dist

ribut

ion

subs

tatio

n

Per

sq.

km

of c

over

age

AGL 2.59 337 42 302 10,714 55 259

Citipower 3.61 70 122 162 6,362 77 1,540

TXU 1.65 13 15 126 13,153 11 6

Powercor 1.20 7 8 96 9,109 9 4

United Energy 3.23 45 53 343 13,385 52 378

3.2 CUSTOMER COMPLAINTS

3.2.1 Statistics published by the Office of the Regulator General8 show an overall improvementin the total CMOS over the period 1995 to 1999 for Powercor customers. 150,000customers on 76 feeders have received a consistently improving service or serviceabove the benchmark. Section 4.5 of this report shows there are 68 feeders and morethan 125,000 customers (24%), who have received a level of reliability that has eitherdeteriorated or has continued (for three years) to be below the proposed benchmarks9.

3.2.2 In addition, there has been a considerable and increasing amount of reporting on failuresto meet the expectations of electricity customers. The local and regional media havereported on many incidents within the Powercor distribution network. Members ofParliament have been aware of the issues and potential causes for a protracted period.

3.3 COMMERCIAL CONSIDERATIONS

3.3.1 A balance has to be achieved by the distribution business between the cost and thereliability of the supply. The probability of failure of any component can be reducedthrough better design and construction, at additional cost. Mitigation against the failureof any single component by installing duplicate items is possible. This increases thesecurity of supply but again at an increased cost. The risks and additional costs,perceived by the transmission and distribution companies in Victoria (and most parts ofthe world), result in the installation of duplicate supply routes from generators to the zonesubstations. Beyond zone substation, except in some high-density areas, the additionalcost of alternative supply routes is not justified. Lower cost equipment (and thereforelower reliability) is generally used to transport electricity from the zone substation to theconsumer. As a consequence most of the interruptions to supply (87% historically in thePowercor area)10 result from failures of either the 22kV feeder from the zone substationor the low voltage supply line from the distribution substation to the consumer.

3.3.2 Customer expectations were much lower both in terms of the quality and the reliability ofthe supply when major parts of the Powercor area was electrified. The configurationadopted (long 22kV radial feeders and the extensive use of SWER - single wire earthreturn systems) was appropriate but limits the reliability achievable.

8 Electricity Distribution Business Comparative Performance for the Calendar year 19989 The targets are detailed in the Distribution Price Review Issues Paper published by the Office10 Section 4 of this report based on an interpretation of Powercor OAS data


Doc No.71321 19/09/00 Page 16

3.3.3 The components of a distribution network have very long asset lives. Many componentsinstalled when an area was first electrified are still in service today. The service theywere intended to achieve has been exceeded as customer expectations have increased.Alternative responses to this are to improve the effectiveness of maintenance, increasethe maintenance or undertake an equipment replacement programme. Powercor hasinvested a considerable effort in raising the standard of the equipment utilised (andthereby the reliability of the system) through good maintenance practices. There is alimit to the level of reliability that can be achieved without undertaking a major investmentin re-design and re-configuration of a network. This is generally only undertaken whendemand has outstripped the supply capability of the network or customer servicedeteriorates below a point considered acceptable by the distribution business. A furthertrade-off therefore is required between short-term low cost small improvements andlonger-term high cost, larger improvements in reliability.

3.4 MANDATORY REQUIREMENTS

3.4.1 The Office of the Chief Electrical Inspector (OCEI) oversees the safety aspects of thesupply of electricity. Safety has a contingent effect on the reliability of the distributionnetwork and on the cost of operating and maintaining the network. The only issue in thisreport associated with the OCEI concerns the restoration procedure after a fault. This iscited in Section 8 of the report.

3.4.2 The Energy Industry Ombudsman and the Office of the Regulator General (the Office)collectively undertake an effective role in monitoring the performance of Powercor andthe other distribution businesses, ensuring that collective customer interests are met andindividual customers are heard. The Office, in its role as Regulator, is currentlydetermining the outcomes of the draft Electricity Distribution Price Review and isresponsible for the Electricity Distribution Code.

3.4.3 The Distribution Code requires the distributor to publish targets for the reliability of supplyfor the following year. As a minimum, these targets must include: -

• The total time customers may experience loss of supply

• The frequency with which supply to customers may be interrupted Includingmomentary interruptions

• The duration of interruptions, excluding momentary interruptions

3.4.4 The Distribution Code states the distributor must use its best endeavours to ensure thatthe duration of interruptions to the supply of electricity to customers’ electricalinstallations does not exceed, on average, 500 minutes per annum in rural areas, and250 minutes per annum in other areas. Powercor is achieving this target.

3.4.5 The Distribution Code as currently enacted requires that an average level of reliability beachieved for all rural and all urban feeders. No specific level of reliability for anyindividual feeder is set. As a consequence there is considerable opportunity for thedistribution businesses to meet the requirements of the Distribution Code to the possibledetriment of a considerable number of consumers in some segments and somelocations. The previous Government prior to privatisation set the Distribution CodeStandards, and the Offices power to vary them has been constrained by the Statement ofGovernment Policy of 1994. Recent amendments to the Electricity Industry Act havesought to address this constraint.

3.4.6 The Office in 1998 implemented public monitoring of low reliability feeders and in 1999adopted the benchmarks proposed by PB Power. Possibly in response to this monitoringPowercor devoted some resources to remedying low reliability on some feeders. Thisinvestigation seeks to understand whether these resources were well targeted and thework well implemented and whether sufficient resources were made available.


Doc No.71321 19/09/00 Page 17

3.5 FACTORS AFFECTING SUPPLY RELIABILITY

3.5.1 There are many potential reasons for perceived poor performance, however there are alimited number of controllable technical deficiencies that cause poor supply reliability.The fundamental causes of poor reliability are associated with the following: -

l Subtransmission and feeder network planning and security standards

l Subtransmission and feeder design standards

l Construction standards

l Plant operating standards

l Asset management strategies

l Asset failure information systems

l Maintenance standards

l Capital investment prioritisation policy and processes

l Application of any of the above standards and policies

3.5.2 External factors such as environmental conditions and weather also have an effect onsupply reliability. The Powercor Electricity Distribution Price Review Submission citesthe following external factors as affecting their distribution network: -

l Powercor Australia’s distribution area covers some of the most fire-prone country inthe world

l Aside from dry conditions, there are pockets of termite infestation, which contributesto pole deterioration

l Sections of the mid Murray Valley area experience very high groundwater salinity

l Harsh windy conditions around the South coast contribute to salt build up oninsulators, resulting in pole top fires and the premature failure of steel pole hardware

l The south coast also features rugged mountainous terrain (particularly in the Otways)

3.5.2 Distribution systems can be designed and maintained to provide satisfactory service in allthese conditions, although clearly the harsher the environment the greater theexpenditure necessary to achieve any consistent level of reliability.

3.6 RELIABILITY PERFORMANCE MEASURES

3.6.1 The analysis of supply reliability requires an understanding of the nature of distributionnetworks. Powercor operate the sub-transmission system that routes power from theterminal stations to the zone substations. Electricity is then distributed from zonesubstations to customers by means of high voltage (to minimise costs) feeders to a pointclose to the consumer where a distribution transformer then reduces the voltage to thesupply level. Practical and economic considerations result in many consumers (often inexcess of 4,000) being connected to the same feeder in a tree/branch like structure. Inorder to separate parts of the feeder for maintenance and to restore supply to someconsumers in the event of one part becoming faulty the feeder is fitted with switches atstrategic points, segmenting the network into “Switching Zones”. Some of the switchingdevices utilised are automatic and permit automatic separation of faulty parts of thenetwork. These reduce the number of customers affected by a fault. Manual devicespermit the restoration of supply to some customers while the fault is being repaired.

3.6.2 Figure 3.6.1 shows in diagrammatic form the variation in the number of customersaffected depending on where the fault is in the network and the variations in the durationof the outage depending on the design of the network. It could be inferred that the fittingof more protective and switching devices to a distribution network reduces the effect of


Doc No.71321 19/09/00 Page 18

outages on customers. This is true to an extent but there are physical limitations to thenumber of devices that can be fitted and more devices means potentially more faults.

3.6.3 The Powercor network will typically receive in excess of 20,000 fault calls in a year, alarge proportion of which will only affect one customer. A means of measuring the effectof these and relating them to an average customer in a consistent and robust way isrequired. The measures utilised are set out in Table 3.6.2. Figure 3.6.1 in this documentalso shows the effects of faults at different parts of the network on these measures.Combinations of the various designs shown here and some additional items ofequipment are utilised to further reduce the effects of faults on customers.

3.6.4 These measures are a useful means to compare the relative performance of distributionnetworks over time and to an extent for the comparison of different networks. The 32111

feeders in the Powercor network vary considerably in terms of demand, (the number andtype of customers served), and the length of the feeder. Disaggregating the networkaccording to these two characteristics enhances analysis of performance of the network,and comparison with other networks. Until 1999, Powercor had recognised feeders asbeing either “rural” or “urban” as set out in the Distribution Code12. More recent work hasimproved on this and segregated on the basis of long rural, short rural and urban, thedefinitions utilised in the Price Review process and set out previously by PB Power13 andshown in Table 3.6.1.

Table 3.6.1 Definition of Feeder Types

Type Total feeder length Variation by feeder demand

Urban Greater than 300 kVA per km of line

Short Rural Less than 200 km Less than 300 kVA per km of line

Long Rural Greater than 200 km Less than 300 kVA per km of line

3.6.5 The measures however do not reflect the differing sensitivity of different customer typesto the number of outages or the duration of them. Customer surveys14 undertaken byPowercor indicate that some customer groups such as dairy farmers are concernedabout momentary interruptions to supply. However, in general customer perception ofthe reliability of the supply derives from the frequency of interruptions (MAIFI and SAIFI)and to a lesser extent the average duration of each outage, CAIDI. Customers aregenerally less affected if the outage is planned ie more than four days notice is given.

11 The number of feeders varies from year to year as Powercor construct new, and reconfigure existing ones.12 The Electricity Distribution Code defines rural lines as having a length of at least 15kms13 PB Power Report 2001 Electricity Distribution Price Review Reliability Service Standards14 Powercor 2001 Electricity Distribution Price Review Submission December 1999


Doc No.71321 19/09/00 Page 19

Figure 3.6.1 The Effect of Distribution Network Faults on Performance Measures

Assumptions

Customers per zone substation 10,000

Customers per feeder 2,000

Customers per distribution transformer 5

Average time for fault crews to reach site 30 minutes

Average fault repair time 120 minutes

ZoneSubstatio

Fault here or here

Fault here or here

Manual switchon Spur Line

Fault here or here

Fault here or here

Fault here or here

66kV Sub TransmissionInterconnection to other

Zone Substations

Fault on feeder backbone or unprotected spur

Customers affected until fault crew arrives – 2,000Customers affected whilst fault repaired – 2,000CMOS 240,000 SAIFI 0.2CAIDI 120 SAIDI 24

22kV

Fee

ders

Supply fromGPU

Low voltagesupply to 20customers

Fault on one distribution transformer

Customers affected until fault crew arrives – 5Customers affected whilst fault repaired – 5CMOS 600 SAIFI 0.0005CAIDI 120 SAIDI 0.06

Fault on fuse protected spur

Customers affected until fault crew arrives – 20Customers affected whilst fault repaired – 20CMOS 2,400 SAIFI 0.02CAIDI 120 SAIDI 0.24

Fault on spur line downstream of a manual switch

Customers affected until fault crew arrives – 2,000Customers affected whilst fault repaired – 20CMOS 61,800 SAIFI 0.2CAIDI 30.9 SAIDI 6.18

Fault on feeder downstream of ACR

Customers affected until fault crew arrives – 1,000Customers affected whilst fault repaired – 1,000CMOS 1,200,000 SAIFI 0.1CAIDI 120 SAIDI 12

Fault on feeder downstream of ACR and Auto switch

Customers affected until fault crew arrives – 500Customers affected whilst fault repaired – 500CMOS 60,000 SAIFI 0.05CAIDI 120 SAIDI 6

Fault hereor here

Fault on Sub transmission or zone substation

Customers affected until fault crew arrives – 10,000Customers affected whilst fault repaired – 10,000CMOS 1,200,000 SAIFI 1CAIDI 120 SAIDI 120

Fault here or here

Fuse onSpur Line

ACR

AutomaticCircuit

Recloser halfway along line

Auto

Automaticswitch

downstreamof a Recloser


Doc No.71321 19/09/00 Page 20

Table 3.6.2 Definition of Performance Measures

Measure Index Description

Total customerminutes offsupply

CMOS:

CustomerMinutes OffSupply

The total minutes all customers combined are withoutelectricity in a year. It comprises both planned andunplanned interruption components.

Calculated as the sum of the product of duration andnumber of customers affected for all outages.

Average minutesoff supply percustomer

SAIDI:

System AverageInterruptionDuration Index

The total minutes, on average that a customer iswithout electricity in a year. It comprises both plannedand unplanned interruption components.

Calculated as the sum of each interruption duration (inminutes) times the number of customers affecteddivided by the total number of customers averaged overthe year.

Average numberof interruptionsper customer

SAIFI:

System AverageInterruptionFrequency Index

The number of occasions per year when the averagecustomer experiences an unplanned/plannedinterruption. (The measure is used for planned,unplanned and total number of interruptions)

Calculated as the sum of all reportedunplanned/planned interruptions, divided by the totalnumber of connected customers averaged over theyear. Unless otherwise stated, SAIFI excludesmomentary interruptions (less than one-minuteduration).

Averageinterruptionduration(minutes perinterruption).

CAIDI:

CustomerAverageInterruptionDuration Index

The average time taken for supply to be restored to acustomer when an unplanned interruption has occurred.

Calculated as the sum of each unplanned interruptionduration in minutes, divided by the total number ofinterruptions (SAIDI divided by SAIFI). Unlessotherwise stated, CAIDI excludes both planned andmomentary interruptions (less than one-minuteduration).

Average numberof momentaryinterruptions percustomer

MAIFI:

MomentaryAverageInterruptionFrequency Index

The total number of momentary interruptions (less thanone minute duration) that a customer could, onaverage, expect to experience in a year.

Calculated as the sum of reported momentaryinterruptions of less than one minute in duration,divided by the total number of customers averaged overthe year.

3.6.6 SAIDI is an output and is the product of the variables SAIFI and CAIDI, but is used asproxy for both although the drivers and methods by which each can be reduced aredifferent. SAIFI, the number of failures is controllable to an extent by Powercor althoughit is also influenced by the fundamental design of the distribution network andenvironmental factors such as the weather and local vegetation. CAIDI is the duration ofthe outage. This measure is determined by the responsiveness of the Powercor callcentre, its fault crew dispatch procedures, the proximity of the fault crews to the fault andtheir success in the implementation of fault location and repair procedures. Thesemeasures can be further subdivided both by the cause of the problem and whether theyare planned or unplanned.


Doc No.71321 19/09/00 Page 21

4 POWERCOR DISTRIBUTION NETWORK PERFORMANCE

KEY POINTS

The causes of outages are not recorded in a standardised way. The introduction ofa state-wide or nation wide scheme for collecting details of primary cause, reason,consequential damage to equipment, and the actions taken would yield benefits for theDistribution Businesses, for the Office and ultimately for the consumer.

Section 4.3

The data collected by Powercor on outages is incomplete. 1997 data in particularappears to be of low accuracy with the outage category unknown being used extensively.Data that is more recent is much more accurate.

Section 4.2

Powercor reliability initiatives relate to whole feeder problems. The Powercorformal approach to analysis of the outage data does not include recognition of theservice being provided to individual customers.

Section 4.3

Average reliability minimum standards do not ensure good service. The standardsset in the Distribution Code are an average value for all rural and urban customers.

Section 4.2

There is no overall improvement in the duration of faults. The duration of faults inurban areas is reducing whilst in rural areas it is increasing.

Section 4.2

There has been a five- percent increase in the fault rate. The fault rate has increasedfrom 28.5 per 100km of HV line to 31.5 (compared with the UK average of around 12).

Section 4.2

At least 8% of Powercor customers have consistently received low supplyreliability. A small number of customers have received deteriorating or very low level ofreliability for 3 years. Eleven percent received low reliability in 1999 and the number isnot reducing. Section 4.5

Detailed analysis of selected feeders more appropriate than a high level audit.Section 4.6

4.1 POWERCOR OUTAGE DATA

4.1.1 The data has a number of shortcomings discussed elsewhere, but is the best availableand when correctly analysed has some value for investigating reliability and focussingreliability improvement efforts.

4.1.2 Powercor were unable to provide data for the first three months of this year due totechnical difficulties with their new customer information system. This has resulted in theselection of feeders on the basis of performance in the year ended December 1999.

4.1.3 Historical performance of the feeders would be better-analysed utilising data from aperiod of more than three years. Data prior to 1997 was not readily available and the lowquality of the 1997 data implies that data from earlier years would be of limited value.

4.1.4 No equipment damage or work done details are recorded in the in OAS. Powercorgenerally do not record details of failed components and therefore any performanceimprovement measure is more difficult to substantiate and measure


Doc No.71321 19/09/00 Page 22

4.1.5 The Powercor OAS data for 1997 has many unplanned outages put down to the cause“Unknown”. This practice was largely although not completely discontinued at the end of1997. All planned outages are also recorded as “Unknown”. The failure to record anyfurther details or reasons for a planned outage is a lost opportunity and has value inascertaining ways in which to reduce interruptions to customers.

4.2 OVERALL NETWORK PERFORMANCE

4.2.1 Table 4.2.1 and Figure 4.2.1 shows the key performance statistics of the Powercornetwork for the three years analysed in this investigation. A six percent improvement inoverall SAIDI from 1997 to 1999 is a relatively small change, particularly when the effectsof environmental factors such as weather are taken into account. Similarly, theimprovements in the duration of faults and the frequency of them are equally small. Theoverall performance is therefore not improving significantly when considered over thisperiod. Analysis undertaken on data for a longer period (from 1990) by PB Power15

indicates that there is an improvement. However, Figure 4.2.2 shows the movement inthe average duration of faults on a monthly basis, the trend line shown on the graphconfirms the lack of any overall reduction in the three-year period 1997 to 1999.

4.2.2 Figure 4.2.3 shows the average duration of a fault by month and clearly displays somesignificant variations between months. Investigation of the causes for these variationsmay assist in reducing the duration of faults overall. Powercor are conscious of the needto reduce the duration of faults. They appear to have a preference though forinvestigating and then investing in expensive high technology solutions (such as linkingcomputers in fault repair vehicles to the centralised computer systems). Low costinvestigation utilising existing data may locate alternative means of reducing the durationof faults. Potential areas for consideration are addressed in section 12 of this report.

Table 4.2.1 Powercor Overall System Performance

Year SAIDI SAIFI CAIDI

1997 252 2.85 88.4

1998 269 3.05 88.2

1999 237 2.70 87.5

Figure 4.2.1 SAIDI SAIFI and CAIDI Trends

0 60

120 180 240 300 360

1995

19

96

1997

19

98

1999

20

00

2001

20

02

2003

20

04

2005

SAID

I & C

AID

I

0.00 1.00 2.00 3.00 4.00 5.00 6.00

SAIF

I

SAIDI Total

SAIDI Unplanned

SAIDI Planned

CAIDI Unplanned

SAIFI Unplanned

15 Preliminary Analysis of the Distributors Submissions 2001 Electricity Distribution Price Review February 2000


Doc No.71321 19/09/00 Page 23

Figure 4.2.2 Average Duration of Faults

0

20

40

60

80

100

120

January1997

July1997

January1998

July1998

January1999

July1999

Min

ute

s

Actual CAIDI

Linear (Actual CAIDI)

Figure 4.2.3 Average Duration of a Fault by Month

0

20

40

60

80

100

120

January March May July September NovemberMonth (January = 1)

Min

ute

s

199719981999Average

c

4.2.3 Table 4.2.2 breaks out the system average interruption duration index (SAIDI) intoplanned and unplanned. Two trends are apparent. The duration of unplanned outageshas increased over the three years by nearly 10%; and the reduction in overall systemSAIDI from 252 minutes in 1997 to 237 minutes in 1999 is largely attributable to thereduction in planned SAIDI from 50 minutes to 39 minutes.

4.2.4 The planned SAIDI remains at relatively high level compared to other DistributionBusinesses in Victoria. An investigation of the reason for this is likely to show thatPowercor could undertake more maintenance with the lines in service preventing aplanned outage. The techniques for working on HV overhead lines live are well provenand most activities can be undertaken live. However, the additional cost is a factor.

Table 4.2.2 Powercor Overall System Performance Planned and Unplanned

Planned Unplanned

Year SAIDI SAIDI CAIDI

1997 50 202 71

1998 39 230 75

1999 39 198 78


Doc No.71321 19/09/00 Page 24

4.2.5 The tables in Appendix B set out the 1997, 1998 and 1999 annual performance of all thefeeders as recorded in the Powercor OAS (Outage Analysis System) data.

4.2.6 The Powercor outage data is the best data available for the analysis in this investigationas it shows every interruption recorded by Powercor (70,000 for the three years 1997 to1999). The data also includes details of the feeder, switching zone, distributionsubstation or customer affected. The outage records also show the number ofcustomers affected, the incident time and duration, and in some cases the cause andreason for the fault. The data is the basis of all the reliability information reported to theOffice. The quality of this data is discussed in detail in Section 4.1 of this report.However, it is important to note that even a cursory review of the data for 1997 and to alesser extent the later years indicates a significant level (up to 20%) of incompletenessand error. Powercor has then improved the data accuracy over the period investigated.

4.2.7 In order to make representative comparisons of the performance of different feeders it isnecessary to normalise the reliability. For the customer minutes off supply (CMOS), thefeeder total CMOS is normalised by the customer numbers16 on the feeder. Thiscalculation results in the SAIDI for the feeder. For the number of interruptions thenormaliser is the length of the feeder (the longer a feeder the more it is exposed toequipment failure or external incidents such as birds animals and lightning). Theresulting information is included in the tables in Appendix B and was utilised in theselection of feeders to investigate as set out in section 5.2.

4.2.8 Figure 4.2.4 presents a view of a deteriorating performance of the Powercor network.The horizontal axis is the percentage of all feeders, ie the number of feeders adjusted forvariations between years, whilst the vertical axis is the number of faults recorded in theOAS data per 100km of HV line17. This measure is a sound comparison of overheaddistribution networks as the feeder length is now immaterial and all planned and singlepremise outages are excluded. The graph shows a deteriorating performance from 1997to 1999 and this is confirmed by the movement in the average number of faults per100km increasing from 28.5 in 1997 through 29.9 in 1998 and reaching 31.5 in 1999.This compares with an average in the UK of around 12 faults per 100km per year. Whilstthese figures are unadjusted for the numbers of customers on the feeders the trend isclearly apparent with around a 5% increase in fault rate occurring each year (some of thisis due to the improved reporting of outages). Powercor SAIFI is not increasing (ordecreasing) significantly, therefore the increase in the number of faults occurring on thePowercor network is being compensated by a reduction in the numbers of customersaffected by faults (mainly through the fitting of ACR’s). For comparative purposes thefault rate of TXU is shown.

16 The customer numbers utilised are as agreed with Powercor the average annual customer numbers on each

feeder.17 The 1999 feeder lengths were used for all years as the lengths from earlier years are known to be inaccurate


Doc No.71321 19/09/00 Page 25

Figure 4.2.4 Fault Rate on HV Feeders

0

20

40

60

80

100

120

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

Percentage of Feeders

Nu

mb

er o

f F

ault

s p

er 1

00km

1999

1997

1998

TXU 1999

4.3 ANALYSIS OF PERFORMANCE BY CAUSE

4.3.1 Analysis of all the sustained outages reported over the three year review period results inapportionment of the outages between the different causes as set out in the pie chart ofFigure 4.3.1.

Figure 4.3.1 Causes of Powercor System Outage Minutes for 1997 to 1999

Subtransmission13%

Planned16%

Single Premises Only1%

Unknown7%

Malfunction13%

Elec Overload4%

Bird4%

Fire3%

Vehicle Impact3%

Not Found Insp3%

Loose/Poor Conn2%

Fallen Tree2%

Other14%

Lightning11%

Polution - Salt/Dust4%

4.3.2 The causes as utilised in the OAS database are not clearly specified, some (electricaloverload/malfunction and lightning/storm activity) appear to have been usedinterchangeably. The adoption of a simplified and more rigorous set of definitionsapplied across the whole Powercor network would add value to the data gathered.


Doc No.71321 19/09/00 Page 26

Additional value would be achieved through the adoption of a statewide or nationalreporting scheme with clear definitions of outage causes, reasons for outages and detailsof the consequential equipment damage and actions taken. Integration with outagerecording systems with other distribution business would extend the depth of thereliability information available and in the long term further reduce the number ofequipment related faults. The Distribution Businesses in the UK utilise a commonrecording system for all outage information (National Fault Information Reporting System,NAFIRS) with common definitions and standards, which has the additional benefit ofenabling better comparison between companies.

4.3.3 To reduce the variability still further Powercor would need to demonstrate value in theaccuracy of the data gathered to the fault repair staff responsible for its collection.Discussions with field staff during the course of the investigation indicated that many didnot take the trouble to accurately report causes as they saw little value in doing so.

4.3.4 The sub-transmission outages are detailed in section 4.4.1. Each of the other causes ofthe outages are detailed further in sections 6 and 8 of this report.

4.3.5 Single premise outages (usually as a result of a fault on the low voltage supply lineentering the premises) constitute a large proportion (35%) of the total number of outagesbut because they only affect by definition one customer the effect in SAIDI is minimal.Most customer minutes lost result not from single premise outages but from outages ofdistribution substations, sections of, or even the whole of the feeder.

4.3.6 Powercor are currently unable to recognise from the outage data how many timesoutages have occurred for a particular customer (the functionality was included in thesuperseded OAS system). This information, had it been available would have yielded avital insight into the service Powercor are providing. Some customers will have had nooutages at all in any of the three years analysed, whilst others will have had a greatnumber. The analysis of how many, where, when and of what cause could be ofsignificant use to Powercor in better targeting the companies reliability improvementinitiatives. These are detailed in Section 10 of this report.

4.4 ANALYSIS OF PERFORMANCE BY NETWORK TYPE

The normalised performance of each feeder type is shown in Table 4.4.1. The tableclearly shows the increase in faults per 100km in 1998 and the return in 1999 to thelevels of 1997. The table also demonstrates the considerably higher number of faults perkm of line for urban feeders which reflects the increased density of equipment arisingfrom poles being more closely spaced and the density of customers being much higher.The normalised measure of faults per 100km of line is therefore only effective within eachfeeder type, or for the whole of the Powercor network given that the proportion of feedersof each type does not change substantially from one year to the next.


Doc No.71321 19/09/00 Page 27

Table 4.4.1 Normalised Faults per 100km of Line

SAIFI / km of HV lineFeeder type / Year

Average

1997 37

1998 60

Urban

1999 37

1997 9

1998 15

ShortRural

1999 9

1997 2

1998 4

LongRural

1999 2

4.4.1 Zone Substations and Sub-transmission

4.4.2 Faults in zone substations and sub-transmission lines contribute 13% of all CMOS. Thissubstantial amount results not from the number of faults which are few (1,372 reportedoutages out of a total 70,931 for the three years analysed) but because each fault resultsin a large number of customers losing supply. The fault restoration times should ingeneral be shorter as alternative supplies are available in most cases. The extension ofremote control facilities to all zone substations as identified in section 12 would furtherreduce the restoration time of these major faults.

4.4.3 The information contained in the OAS outage database does not permit the separation ofoutages between faults in zone substations and the sub-transmission lines. Theanticipation is that the majority of faults will be associated with the sub transmission lines.The faults in the zone substation/ sub-transmission network are set out in Figure 4.4.1.Given that the causes of outages shown in this figure are similar to the faults for thewhole network (Figure 4.3.1) reducing the incidence of faults will require a similarapproach to that required for the distribution feeders. The effect of the outages couldlargely be eliminated if the sub transmission system was extended to include duplicationof supplies to all zone substations. Currently the security of supply standard does notrequire this. The viability of this should be evaluated in conjunction with ascertainingboth the customer’s willingness to pay for a long-term improvement in reliability and theneed for augmentation to meet capacity requirements.


Doc No.71321 19/09/00 Page 28

Figure 4.4.1 Causes of Zone Substation and Sub Transmission Outages

1997 Zone Substation Faults and Sub Transmission FaultsTotal CMOS 20,655,859 Minutes

Unknown41%

Malfunction4%Lightning

16%

Bird5%

Not Found Insp8%

Empl Accidental

4%

Other19%

Elec Overload3%


Unknown16%

Malfunction25%

Lightning10%

Fire18%

Poll - Salt/Dust18%

Bird4%

Other3%

Elec Overload4%


Unknown17%

Malfunction16%

Lightning16%Fire

11%

Poll - Salt/Dust5%

Bird8%

Other10%

Elec Overload15%

4.4.4 Long rural performance

4.4.5 Figure 4.4.2 1999 Long rural CMOS by Cause and Figure 4.4.3 1999 Long Rural byNumber of Interruptions illustrate the high proportion of long rural CMOS resulting formlightning. This feature of long rural feeders is discussed further in section 6 of this reportas is the problems with birds, which constitutes 15% of the interruptions.

Figure 4.4.2 1999 Long rural CMOS by Cause

Lightning33%

Malfunction20%

Elec Overload8%

Bird7%

Animal2%Loose/Poor Conn

3%

Unknown1%

Others5%Vibration

2%

Corrosion/Infest2%

Poll - Salt/Dust3%

Vehicle Impact3%

Fire3%

Rot/Decay4%

Fallen Tree4%


Doc No.71321 19/09/00 Page 29

Figure 4.4.3 1999 Long Rural by Number of Interruptions

Lightning22%

Malfunction23%

Elec Overload16%

Bird15%

Vibration1%

Corrosion/Infest2%

Animal5%

Loose/Poor Conn4%

Poll - Salt/Dust1%

Fire1%

Rot/Decay1%

Others6%

Unknown1%

Vehicle Impact1%

Fallen Tree1%

4.4.6 Short rural performance

Figure 4.4.4 Short Rural Number of Interruptions by Cause

Malfunction27%

Lightning9%

Loose/Poor Conn7%

Elec Overload22%

Others9%

Bird12%

Unknown2%

Rot/Decay1%

Corrosion/Infest3%

Vandalism2%

Dug-Up1%

Fire0%

Vehicle Impact2%

Fallen Tree1%

Poll - Salt/Dust2%

4.4.7 Notable for the short rural feeders is the relatively high proportion of outages caused byelectrical overloads in 1999. Malfunction accounts for 27% of the outages and at 24% ofthe CMOS is the largest single cause of outages for short rural feeders.

4.4.8 Urban performance

4.4.9 There has been a noticeable reduction in the average duration of faults in urban areasand a minor deterioration in the duration of the faults over the three-year period for ruralcustomers. This is demonstrated in Figure 4.4.5.


Doc No.71321 19/09/00 Page 30

Figure 4.4.5 Average Duration of a Fault for Urban and Rural Feeders

0

20

40

60

80

100

120

140

160

January1997

July1997

January1998

July1998

January1999

July1999

Min

ute

s

RURAL

URBAN

Linear (URBAN)

Linear (RURAL)

Figure 4.4.6 Urban Feeders Interruptions by Cause

Malfunction27%

Bird6%

Elec Overload23%

Lightning4%

Unknown2%

Fire0%

Poll - Salt/Dust1%

Empl Accidental3%

Animal1%

Rot/Decay2% Others

17%

Loose/Poor Conn10%

Vehicle Impact2%

Clashing1%

Fallen Tree1%

4.4.10 Just two cause, electrical overload and the interchangeably used malfunction account forover fifty percent of the urban CMOS as shown in Figure 4.4.6. An effective targeting ofthese would reduce the Powercor CMOS significantly.

4.5 RELATIVE PERFORMANCE TRENDS

4.5.1 Reliability is measured in absolute terms with the measures, SAIDI, SAIFI and CAIDI asset out in section 3.6 of this report. Trends in performance are considered in astraightforward manner as relative changes over time. There is an inherent complexitywhen considering whether a level of performance is satisfactory given that any level isbased on judgement. As a consequence, a number of measures have evolved. TheDistribution Code as detailed in section 3.4 of this report sets standards for average notspecific urban and rural feeder performance. This shortcoming, as noted previouslyencourages Powercor to have instigated measures that reduce the average minutes offsupply for the average customer in the most cost-effective way. This would result in agreater improvement in reliability where the customer density is greatest to the detrimentof the remainder of the network. There is no clear evidence of this having taken placeand contrary to this Powercor has a watch list of eighteen feeders.


Doc No.71321 19/09/00 Page 31

4.5.2 There are three measures (appropriate to varying degrees) of the acceptability of theservice provided to customers by Powercor.

1 The Distribution Code requires Powercor to provide a minimum standard of service.The Distribution Code minimum standards do not ensure good service as they arebased on average values for all rural and all urban customers.

2 Benchmarks have been proposed as a result of the Electricity Distribution PriceReview process. These measures include the benchmarks proposed by PB Power18

and the standards to be set in the 2001 to 2005 Price Review Decision. This latterstandard proposes for each Distribution Business a target for 2001 and a moredifficult target for 2005.

3 The third and most robust measure is the consideration of the number of customersreceiving a level of service significantly below the average provided to customers ofPowercor in that year. Figure 4.5.3 shows the number of customers receiving a level ofreliability two, three and four times poorer than the average for that year. Overall there islittle change in the proportions of two, three and four times from 1997 to 1999 indicatingthat the relative reliability of supply to customers on the poorest feeders is unchanging.Any attempts therefore by Powercor to improve reliability are not having a significantimpact on low reliability feeders.

4.5.3 It is this third way of defining low reliability that is the most robust. Weather events suchas high rainfall and lightning, whilst more intense in certain parts of the distribution areaserved by Powercor, is likely to affect all parts of the network to a degree. Relativeperformance of a feeder to the average for that feeder type will therefore overcome thevariation inherent in comparisons with a fixed benchmark. Those feeders with a level ofreliability as measured by the SAIDI of more than twice the average are considered to below reliability. This is an arbitrary value, nevertheless to receive a level of reliability twicethat of the average is a significant change that would be very noticeable to customers.

4.5.4 The tables in Appendix C set out the performance category as recorded in the PowercorOAS system data for all the feeders. The performance categories were based on theSAIDI values and referenced to the Distribution Code standards as set out in Table 4.5.1.

Table 4.5.1 Definition of Feeder Historical Performance Category

Consistently Poor reliability for all three years was worse than 500minutes for a rural feeder or 250 minutes for anurban feeder

Consistent Deterioration reliability deteriorated from 1997 to 1998 andagain from 1998 to 1999

Deterioration then an improvement reliability in 1998 was lower than in 1997 but1999 reliability was better than 1998

Improvement then a deterioration reliability in 1998 was better than in 1997 butthen reliability deteriorated in 1999

Consistent improvement reliability improved from 1997 to 1998 andagain from 1998 to 1999

Consistently good reliability was better than 500 minutes for arural feeder and 250 minutes for an urbanfeeder for all three years

4.5.5 Table 4.5.2 shows a summary of this analysis for the 244 feeders that have remainedsubstantially unchanged throughout the period 1997 to 1999.

18 2001 Electricity Distribution Price Review Reliability Service Standards


Doc No.71321 19/09/00 Page 32

4.5.6 In comparison to the Distribution Code standards of 500 minutes for rural areas and 250minutes for urban areas: -

• Seven feeders have consistently performed below the required level and a furthersixteen have shown a consistent deterioration in performance over the three years.In total 42,583 consumers have received this below target level of service. More thanhalf (22,874) of these customers are served by urban feeders

• In 1997 thirty seven feeders were below the required average level, in 1998 forty sixwere and in 1999 forty one

4.5.7 Figure 4.5.1 shows the distribution of reliability performance for Powercor customersrelative to the Distribution Code requirements. It shows that in 1999 70,000 or 12% ofPowercor’s customers received a service with reliability below the required average level.

4.5.8 Figure 4.5.2 shows the same information for 1997 when 62, 000 customers received asupply standard below these average target reliability levels. These figures make itapparent that the majority of Powercor customers are receiving a more reliable supplythan the standard set in the Distribution Code. The Distribution Code though is notpreventing some customers (12%) receiving a low level of reliability.

Figure 4.5.1 1999 Reliability Relative to Distribution Code Standard

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

400,000

450,000

500,000

550,000

0 0.5 1 1.5 2 2.5 3 3.5 4 4.5

Reliability relative to Distribution Code Requirement

Nu

mb

er o

f C

ust

om

ers

70,000 customers are receiving service below the Distribution Code Required Level

Figure 4.5.2 1997 Reliability Relative to Distribution Code Standard

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

400,000

450,000

500,000

550,000

0 0.5 1 1.5 2 2.5 3 3.5 4 4.5

Reliability relative to Distribution Code Requirement

Nu

mb

er o

f C

ust

om

ers

62,000 customers are receiving service below the Distribution Code Required Level


Doc No.71321 19/09/00 Page 33

Table 4.5.2 Powercor customers receiving poor or deteriorating service against current standards

Based on Distribution Code (SAIDI of 250 minutes urban and 500 minutes rural)

Number of feeders of each performance type Number of bad or consistently deterioratingfeeders

Number of Customers affected by bad orconsistently deteriorating feeders

Con

sist

ently

belo

wbe

nchm

ark

Con

sist

ent

Det

erio

ratio

n Det

erio

rate

dth

enim

prov

ed

Impr

oved

then

dete

riora

ted

Con

sist

ent

impr

ovem

ent Con

sist

ently

abov

ebe

nchm

ark

Tot

alfe

eder

s in

use

for

> 2

year

s

Urban ShortRural

LongRural

Total Urban ShortRural

LongRural

Total

7 16 24 18 9 170 244 11 5 7 23 22,874 9,939 9,769 42,583

8% 5% 8% 7% 12% 5% 7% 8%

Based on Electricity Distribution Price Review Proposed targets for 2001



Con

sist

ently

belo

wbe

nchm

ark

Con

sist

ent

Det

erio

ratio

n Det

erio

rate

dth

enim

prov

ed

Impr

oved

then

dete

riora

ted

Con

sist

ent

impr

ovem

ent Con

sist

ently

abov

ebe

nchm

ark

Tot

alfe

eder

s in

use

for

> 2

year

s

Urban ShortRural

LongRural


LongRural

Total

17 33 51 41 19 83 244 19 18 13 50 36,162 33,848 19,122 89,132

15% 18% 14% 16% 19% 18% 13% 17%


Doc No.71321 19/09/00 Page 34

Table 4.5.3 Powercor customers receiving poor or deteriorating service against proposed standard

Based on Electricity Distribution Price Review Proposed targets for 2005



Con

sist

ently

belo

wbe

nchm

ark

Con

sist

ent

Det

erio

ratio

n Det

erio

rate

dth

enim

prov

ed

Impr

oved

then

dete

riora

ted

Con

sist

ent

impr

ovem

ent Con

sist

ently

abov

ebe

nchm

ark

Tot

alfe

eder

s in

use

for

> 2

year

s

Urban ShortRural

LongRural


LongRural

Total

30 32 55 48 21 58 244 21 24 17 62 46,159 44,886 25,805 116,850

16% 24% 18% 19% 24% 23% 17% 22%

Based on PB Power Benchmarks19 (SAIDI of 130 minutes urban and 178 minutes short rural and 316 minutes long rural)



Con

sist

ently

belo

wbe

nchm

ark

Con

sist

ent

Det

erio

ratio

n

Det

erio

rate

dth

enim

prov

ed

Impr

oved

then

dete

riora

ted

Con

sist

ent

impr

ovem

ent

Con

sist

ently

abov

ebe

nchm

ark

Tot

al fe

eder

sin

use

for

> 2

year

sUrban Short

RuralLongRural


LongRural

Total

32 36 55 45 21 55 244 19 23 26 68 36,162 41,720 48,069 125,951

16% 25% 29% 22% 19% 22% 32% 24%

19 PB Power 2001 Electricity Distribution Price Review Reliability Service Standards report to the Office of the Regulator General August 1999


Doc No.71321 19/09/00 Page 35

4.5.9 In comparison (Table 4.5.3) to the publicised benchmarks in the Distribution PriceReview20 for Powercor of 315.6 minutes for a long rural 177.6 minutes for a short ruraland 130 minutes for an urban feeder: -

• Thirty-two feeders have consistently performed below the required level and afurther thirty-six have shown a consistent deterioration in performance over thethree years. In total 125,951 consumers have received this level of service. Ruralfeeders serve more than two thirds (89,789) of these customers.

4.5.10 Table 4.5.2 and Table 4.5.3 show the performance against the targets anticipated to beincluded in the Price Review Determination. These tables demonstrate that at least 8%of all Powercor customers have been receiving either a deteriorating service or a level ofservice that has remained below the average targets set in the Distribution Code. Thenumber of customers receiving a low reliability level relative to the PB Powerbenchmarks is shown in Figure 4.5.3 for 1997 and 1999. There is some deterioration asevidenced by the number of customers receiving a level of reliability three times or morepoor than the benchmarks having increased from 20,000 to 25,000 from 1997 to 1999.The deterioration overall is not significant, of greater concern is that there is has been noimprovement in the reliability of supply to customers on low reliability feeders.

Figure 4.5.3 Low Reliability Relative to the PB Power Benchmarks in 1997 and 1999

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

2 3 4 5 6 7 8 9

Reliability Relative to PB Power Benchmarks

Nu

mb

er o

f C

ust

om

ers

1999, 25,000 customers are receiving service more than three times poorer than Benchmark Level

1997, 20,000 customers are receiving service more than three times poorer than Benchmark Level

4.5.11 Figure 4.5.4 and Figure 4.5.5 show the performance against the average for each year.The underlying message is again that there has been no major deterioration orimprovement in terms of the number of customers receiving a service reliability of two,three and more times the average. Reliability more than twice the average could beconstrued as low reliability, in that it is difference readily noticeable by customers. Onthis basis more than 60,000 customers (11%) have received a low reliability.

20 Distribution Price Review Issues Paper published by the Office


Doc No.71321 19/09/00 Page 36

Figure 4.5.4 1997 and 1999 Reliability Relative to the Average for the Year

0

100,000

200,000

300,000

400,000

500,000

0 0.5 1 1.5 2 2.5 3 3.5 4 4.5 5

Reliability Relative to the Average

Nu

mb

er o

f C

ust

om

ers

1997

1999

Figure 4.5.5 Low Reliability Relative to the Average Feeder Reliability

0

10,000

20,000

30,000

40,000

50,000

2 3 4 5 6 7 8 9

Reliability Relative to the Average

Nu

mb

er o

f C

ust

om

ers

1997

1999

4.6 INVESTIGATION OF POOR FEEDER RELIABILITY

4.6.1 A significant proportion of Powercor customers as shown in Table 4.5.2 and Table 4.5.3are experiencing low reliability. This aligns with the qualitative view of the increasingmagnitude of customer complaints and media interest in Powercor’s failure to provide areliable service to some customers. Powercor have met the reliability targets set out inthe Distribution Code, however they have continued to provide service to both some ruraland urban customers that is considerably below the targets set.

4.6.2 In order to determine the reasons for poor and deteriorating reliability with some rigour itwas necessary to undertake this investigation. The overall process is set out in Section 2of this report.


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4.6.3 Two alternative approaches to understanding the reliability problems could have beenundertaken. The investigation of a selection of feeders, carefully chosen asrepresentative of the whole network or the alternative, top down audit type approach.The audit approach would not have achieved the same level of insight into the problemsthat this investigation has revealed. The combination of extracting information from thedetailed analysis of all the outage data, the physical examination of the feeders andstructured interviews with the key staff in both provincial and corporate offices is a moreeffective way to determine the cause of poor feeder reliability.

4.6.4 The risks with the approach adopted arise from making inappropriate selections offeeders to investigate. Developing a thorough and repeatable basis for selectingfeeders, which sufficiently accurately represent all the feeders, and factors affectingfeeder reliability mitigated against this.


Doc No.71321 19/09/00 Page 38


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5 SELECTION OF FEEDERS FOR DETAILED INVESTIGATION

KEY POINTS

A comprehensive methodology resulted in the selected feeders beingrepresentative of the network. Selection based on detailed modelling and analysis ofall feeder types, performance, performance trends and other influencing factors wasundertaken on a rigorous and repeatable basis. Consequently, the selected feederscover all the potentially contingent factors on supply reliability.

Sections 5.2 and 5.4

Powercor were unable to provide current data. Problems with the Powercor outagemanagement system prevented the use of current data when selecting the appropriatefeeders for analysis. The analysis is based on January 1997 to December 1999 data.

Section 5.1

Powercor appear slow to eliminate the major causes of outages. The same cause isa major contributor to CMOS for consecutive years.

Section 5.3

Half of the CMOS for some feeders is attributable to one cause. For many of theselected feeders, the one cause accounts for over 50% of the total CMOS. Eliminationof outages due to this cause alone would be very effective.

Section 5.3

5.1 BASIS OF SELECTION

5.1.1 Ideally the investigation of Powercor would cover all parts of their distribution business assupply reliability provided to customers is contingent to a greater or lesser extent on thewhole business. In order to achieve in a timely manner the objectives set out in Section2.2 the investigation focused on a selection of the 22kV feeders. The environment, thedesign, service expectations, accessibility and other key issues affecting theperformance of feeders varies between feeders. In order to achieve a level ofinvestigation sufficient to be able to extend the findings to the whole network it wasnecessary to select a number of feeders with variations of the following features: -

• Feeder types, i.e. Long Rural, Short Rural and Urban

• Feeder geographic locations

• Feeder customer bases and customer awareness levels

• A combination of feeders from different and from the same zone substation

• Feeder current total (planned and unplanned) reliability performances

• Feeder historical performances

• Feeders with different types of faults affecting reliability

5.1.2 Data from the Powercor OAS for the last three complete years (1999, 1998 and 1997)was analysed in association with the Powercor network diagram21 and an understandingof the geographic and demographic issues of the area served. Outages associated withzone substation or the sub-transmission system were excluded from the analysis.

21 Document P11 Powercor Electricity Network Diagram


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5.2 SELECTING FEEDERS FOR INVESTIGATION

5.2.1 The criteria resulted in the selection of the feeders shown in Table 5.2.1. These werereviewed and tested with the Office to ensure a sufficient coverage of the requisiteissues, and that investigation centred on these feeders would achieve the objectives setout in Section 2.2. Section 5.3 demonstrates that the feeders selected had a range offaults representative of those occurring throughout the network.

5.2.2 Table 5.2.1 shows the performance of the selected feeders over the period 1997 to 1999.Definitions of the categories are set out in Section 4.5 of this report. It demonstrates thatthese feeders had performance histories biased towards poor and deterioratingperformance as required in order to aid the analysis of the causes of poor performance.

Table 5.2.1 Selected Feeder Historical Performance Category

Historical Performance CategorySelectedFeeder

Feeder Type

Con

sist

ently

Poo

r

Con

sist

ent

Det

erio

ratio

n

Det

erio

ratio

nth

en a

nim

prov

emen

t

Impr

ovem

ent

then

ade

terio

ratio

n

Con

sist

ent

impr

ovem

ent

Con

sist

ently

good

BAN008 Long rural 4

HMS002 Long rural 4

TRG005 Long rural 4

BAN015 Short rural 4 4

STN003 Short rural 4

WPD014 Short rural 4

WND012 Short rural 4

TRG001 Short rural 4

SU005 Urban 4 4

SU004 Urban 4 4

GL022 Urban 4

5.2.3 Table 5.2.2 shows the 1999 statistics of the selected feeders grouped according to type.The Distribution Customer number is the average number of customers supplied by eachfeeder in 1999. The SAIDI shown is the 1999 planned and unplanned SAIDI for thefeeder, excluding interruptions due to sub transmission system or zone substationoutages. The “Affected Customers” is the total number of customers affected by theoutages (some customers may feature more than once if they incurred multiple outages).SAIFI is the average number of outages seen by the average customer supplied by thefeeder in 1999. The “No of Supply Interruptions” is the total number of outages affectingany customer connected to the feeder excluding those resulting from zone substation orsub transmission outages. Some outages will have affected only one customer; othersmay have affected all the customers on the feeder.


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Table 5.2.2 Selected Feeder Performance in 1999

Fee

der

typ

e

Zo

ne

Su

bst

atio

n

Fee

der

ID

Len

gth

(km

)

Max

. dem

and

(MV

A)

Dis

trib

uti

on

Cu

sto

mer

s

No

of

sup

ply

inte

rru

pti

on

s

Aff

ecte

dC

ust

om

ers

SA

IFI

SA

IDI (

min

)

Long Rural Average 462 6 1,919 124 5,592 2.9 333

Terang TRG005 239 4 1,235 281 15,071 12.2 1,974

Ballarat North BAN008 372 10 4,164 239 30,884 7.4 1,094

Horsham HMS002 1,524 4 2,928 248 6,180 2.1 221

Short Rural Average 76 6 2,002 67 3,981 1.9 174

Woodend WND012 25 10 986 97 10,810 11.0 1,176

Terang TRG001 114 3 429 82 1,551 3.6 666

Shepparton STN003 40 3 782 59 2,592 3.2 524

Waurm Ponds WPD014 183 8 3,030 148 9,917 3.3 229

Ballarat North BAN015 51 7 3,492 40 4,187 1.2 73

Urban Average 13 7 1,513 33 2,264 1.5 120

Sunshine SU005 28 12 514 36 4,917 9.6 827

Geelong GL022 10 5 3,468 77 10,837 3.1 275

Sunshine SU004 4 6 497 25 391 0.8 93

5.3 ANALYSIS OF OUTAGE DATA FOR SELECTED FEEDERS

5.3.1 Table 5.3.1 shows the largest and second largest causes of outages for each of theselected feeders for the years 1997, 1998 and 1999. The CMOS values quoted relate tothe total customer minutes off supply arising from both planned and unplanned work onthe feeder but excludes outages caused by sub-transmission or zone substations faults.(These were removed from the data based on detecting coincident fault times on multiplefeeders from a zone substation.) The percentage of the total figure indicates theproportion of the total CMOS for customers on the feeder that year attributable to thecause shown


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Table 5.3.1 Major Causes of Outages on the Selected Feeders

Largest cause of feederCustomer Minutes off Supply

Second largest cause of feederCustomer Minutes off SupplyFeeder ID Year

Cause CMOSMinutes

% oftotal

Cause CMOSMinutes

% oftotal

1999 Lightning 2,807,514 62% Overload 990,195 22%

1998 Animal 444,605 30% Overload 290,135 19%BallaratNorthBAN008 1997 Customer fault 748,608 27% Employee 686,366 24%

1999 Vehicle 186,856 73% Lightning 17,309 7%

1998 Malfunction 771,883 61% Pollution 278,752 22%BallaratNorthBAN015 1997 Vehicle 170,891 67% Unknown 32,619 13%

1999 Malfunction 813,321 85% Vibration 83,608 9%

1998 Clashing 88,093 33% Overload 83,422 31%GeelongGL022

1997 Unknown 57,085 51% Vehicle 28,504 25%

1999 Poor con. 192,316 30% Lightning 165,775 30%

1998 Lightning 1,850,815 55% Malfunction 742,357 22%HorshamHSM002

1997 Unknown 1,034,891 53% Lightning 408,727 21%

1999 Unknown 333,245 81% Lightning 38,198 9%

1998 Bird 68,206 41% Lightning 67,488 40%SheppartonSTN003

1997 Not found 21,981 54% Unknown 15,552 38%

1999 Unknown 15,542 34% Bird 13,310 29%

1998 Poor connect. 15,566 50% Overload 7,337 24%SunshineSU004

1997 Unknown 53,779 76% Tree clearing 14,732 21%

1999 Bird 229,815 54% Clashing 89,194 21%

1998 Malfunction 154,911 31% Clashing 138,295 28%SunshineSU005

1997 Unknown 880,790 56% Vehicle 320,374 20%

1999 Malfunction 174,137 61% Lightning 70,099 25%

1998 Vehicle 66,478 27% Pollution 48,990 27%TerangTRG001

1997 Lightning 332,552 66% Unknown 89,160 18%

1999 Lightning 1,300,431 53% Malfunction 330,788 14%

1998 Malfunction 198,804 31% Unknown 135,530 21%TerangTRG005

1997 Unknown 459,678 52% Lightning 187,891 21%

1999 Malfunction 166,299 24% Lightning 151,248 22%

1998 Malfunction 491,761 42% Pollution 205,330 18%WaurmPondsWPD014 1997 Unknown 233,832 56% Animal 66,920 16%

1999 Malfunction 931,468 80% Unknown 99,149 9%

1998 Animal 705,452 56% Fallen tree 272,404 21%WoodendWND012

1997 Unknown 151,815 61% Animal 47,604 19%

5.3.2 The data has a number of shortcomings noted elsewhere but there are some significantissues apparent from the analysis of the largest and second largest causes of outagesfor the selected feeders as shown in Table 5.3.1: -

• There are several instances where a cause is listed in consecutive years, i.e. itwas not eliminated or mitigated but continued to cause disruptions in followingyears. A decisive response to the problem could have eliminated this.


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• In 1999 for eight of the eleven selected feeders, the major outage cause accountsfor over 50% of the total CMOS. Elimination of this one cause if economic andpractical would halve the total minutes off supply encountered by customers onthese feeders.

• Malfunction and overload are major contributors to outages. The terms are usedinterchangeably by fault staff although when the faults are investigated in detail asin Section 6 of this report there are clear differences. Malfunction is often theresult of equipment failure and outages due to overload the result of age orinsufficient adjustments to the capacity of network components as demandincreases. Better asset design, maintenance and operation would reduce oreliminate these outages.

• The OAS data in 1999 alone shows lightning was either the major or the secondmajor cause of outages on seven out of the eleven feeders selected. Thissuggests that measures being taken by Powercor to reduce this are worthy offurther investigation. Section 7 of this report sets out the approach taken tomitigate against the effects of lightning. Lightning is the initiator of an outage, butinadequate lightning protection measures lead to equipment failure, which thencauses the outage or a subsequent outage.

5.4 APPLICATION OF THE INVESTIGATION TO THE REST OF THE POWERCOR NETWORK

5.4.1 The same causes of the outages on the selected feeders are also apparent in theanalysis of the causes of outages for the whole network (Section 4.3 of this report).Table 5.4.1 compares the causes of outages occurring in 1999 (the year with the mostaccurate data) for all the feeders with the causes of outages occurring on all the feedersselected. Of the top fifteen causes of outages, the selected feeders similarly representall but four and only one cause (Unknown) is not represented at all. These tablesdemonstrate that although the feeders represent a high proportion of all the CMOS ofsupply (11%) as opposed to percentage of the customers, % of the HV lines and % ofthe demand they are representational of the whole Powercor network.

Table 5.4.1 Comparison of All the Selected Feeders with All the Network, 1999 Data

Selected Feeders Outage Causes All Feeders

25.0% Malfunction 24.3%

42.7% Lightning 21.0%

10.4% Elec Overload 8.0%

4.2% Bird 7.7%

2.3% Vehicle Impact 5.1%

1.9% Loose/Poor Conn 4.4%

2.6% Poll - Salt/Dust 4.2%

1.3% Fallen Tree 4.1%

1.1% Fire 3.5%

0.4% Rot/Decay 2.7%

Unknown 1.9%

0.9% Corrosion/Infest 1.8%

1.1% Animal 1.8%

0.9% Clashing 1.5%


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5.4.2 Table 5.4.2 compares the causes of the selected feeders with the rest of the Powercorfeeders within each feeder type. Four or more of the top causes of outages on allfeeders form a similar proportion of the outages occurring on the selected feeders. Theselected feeders are representative with regard to the causes of the faults occurring.

Table 5.4.2 Comparison of Selected Feeders with All Feeders by Type, 1999 Data

Urban Feeders

SelectedFeeders

Outage Causes All UrbanFeeders

59.0% Malfunction 33.2%

17.5% Bird 8.6% In these tables text in italics

2.3% Elec Overload 8.1% is used to show : -

1.6% Vehicle Impact 7.5% Where there is a good match

4.8% Lightning 5.5% between the causes of outages on

6.4% Clashing 5.3% on the selected feeders and all

0.2% Fallen Tree 4.7% the Powercor feeders of that type

1.2% Loose/Poor Conn 3.6%

0% Unknown 3.4%

Fire 3.3%

Poll - Salt/Dust 2.9%

0.1% Empl Accidental 2.0%

Short Rural Feeders Long Rural Feeders

SelectedFeeders

Outage Causes All shortrural feeder

SelectedFeeders

Outage Causes All longrural feeder

56.4% Malfunction 23.8% 58.7% Lightning 33.7%

14.8% Lightning 12.0% 8.8% Malfunction 20.1%

0.1% Loose/Poor Conn 8.5% 13.8% Elec Overload 8.0%

4.3% Elec Overload 8.0% 2.3% Bird 7.2%

2.0% Bird 7.9% 0.6% Fallen Tree 3.7%

6.2% Poll - Salt/Dust 7.4% 0.6% Rot/Decay 3.5%

8.8% Vehicle Impact 6.4% 1.4% Fire 3.5%

0.6% Fire 3.8% 0.4% Vehicle Impact 3.3%

1.6% Fallen Tree 3.5% 2.0% Poll – Salt/Dust 3.1%

% Dug-Up 2.9% 2.7% Loose/Poor Conn 2.6%

% Vandalism 2.2% 0.2% Vibration 2.0%

% Corrosion/Infest 2.2% 1.3% Corrosion/Infest 1.8%

5.4.3 The selected feeders were utilised as the platform for the rest of the investigation. Theevaluation and comments in the remainder of this report are therefore related to thesefeeders. Whilst these feeders represent performances poorer than the average, theissues raised as a result of the investigation in Sections 7 to 13 in this report are, in manycases, applicable to all the Powercor network.


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6 FEEDERS INVESTIGATED

6.1 FIELD INVESTIGATION OF FEEDER PERFORMANCE

6.1.1 The following reports on each feeder result from field visits and additional analysis of thefault data. Powercor staff responsible for key aspects of planning, design, construction,operation and maintenance of the feeders were interviewed and extensive parts of thesefeeders were inspected. For each of the feeders, a table summarises the performanceand other relevant items for the 3-year period being investigated. The SAIDI figure is thenumber of minutes in each year the average customer would have been without power.SAIFI is the number of interruptions the average customer would have been subjected toin the year and CAIDI the average duration of the interruptions that year. The DemandMVA figure is the maximum recorded demand on the feeder in the year; increases resultfrom more, or larger customers supplied by the feeder. Decreases from one year to thenext in feeder length and demand usually relate to re-arrangements of the feeder.

6.2 SELECTED LONG RURAL FEEDERS

6.2.1 Terang TRG005

SAIDI SAIFI CAIDI Planned CMOS Demand MVA Length km

1997 429 3.36 127 35.8% 8.9 417

1998 256 2.42 106 21.3% 9.2 417

1999 1,976 12.2 162 9.2% 4.2 239

Operating Environment

6.2.2 TRG005, a 239 km long rural feeder supplies 1,235 customers in flat, open dairyingcountry. The reduction in demand in April 1999 results from the transfer of Timboon andthe Port Campbell tourist area to TRG003. The increase in SAIDI in 1999 when thefeeder length was reduced is counter to expectations but results from a large number oflightning incidents (five times more than occurred in 1998 or 1997).

Outages and Avoidance Measures

6.2.3 Lightning is prevalent in this area with severe lightning storms between January andMarch. It is a serious problem for this feeder and caused 46% of all unplanned CMOSover the three-year review period, with a total of 114 outages. Lightning caused 59% ofunplanned CMOS in 1999. More than half of this (36% of 1999 CMOS) resulted from awhole feeder fault on 28 January 1999 lasting 215 minutes and a second on 2 March1999 lasting five and a half hours. Field staff reported that, in at least one of thesecases, TRG003 and TRG005 were both hit by lightning at the same time and it was notpossible to transfer any load. There are a number of locations seen where animprovement in the way lightning arrestors are fitted (as detailed in Section 8 of thisreport) could have reduced the effect of lightning. Most of the rest of the CMOSattributed to lightning results from damage to distribution substations. Powercor’sphilosophy of not fitting lightning arrestors to transformers of less than 25kVA is commonpractice but does result in damage to small transformers from lightning.

6.2.4 Electrical Overload and Malfunction fault designations were used interchangeably byPowercor until recently. This is clearly a hindrance to resolution of faults and has nowbeen addressed. However during the period 1997 to 1999 Malfunction was the secondlargest cause of CMOS. Most faults designated electrical overload were caused by fuseoperation either at premise or substation level. It would appear that four took out spurline fuses while 4 caused ACR protection devices to operate. Both malfunction and


Doc No.71321 19/09/00 Page 46

electrical overload are equipment age or system operation related problems. Powercorestimates show that these outages could be resolved for $90,000 per rural feeder. Therewere 6,500 customers affected by the 138 malfunction or electrical overload outagesduring the period investigated.

6.2.5 Corrosion is another serious problem, particularly around Peterborough where thestrong westerly winds bring with them salt which produces the severe corrosionobserved. TRG005 would appear to be in the most severe climatic environment of any ofthe eleven feeders studied for this report. The area close to the coast is prone to fruitfungi infestation, which undermines the strength of wooden crossarms. This resulted in16 outages and 3% of the total CMOS for the period.

6.2.6 Possums and birds are also a problem, generally causing blown transformer fuses.Almost 10% of the interruptions during the three-year review period were attributed tobirds. The targeted application of bird covers on steel crossarms and the appropriateinsulation of high voltage structures would reduce this significantly at a cost of $140,000.

6.2.7 Pole Fires. Three outages (4% of total CMOS) over the review period were caused bypole fires. The feeder is constructed to standard SEC design. However only 60-70% ofrequired pole top upgrades for pole fire mitigation has been completed. Completion ofthis work would remove, or substantially reduce the risk of further outages from polefires. Given that pole fires are a much greater problem on other feeders it is difficult tojustify raising the priority of completing the pole top upgrade work.

6.2.8 Fault Response is the responsibility of the Terang Local Service Agent who is able tomanage service calls and faults that can be repaired with just a ladder for access.Support is available from the Warrnambool depot as required, particularly for largerrepair jobs such as the replacement of a pole or a transformer.

6.2.9 The fault duration times for this feeder are near the long rural feeder average so faultlocation is not a major problem. In some areas (between O’Connors Lane and MoreysRoad) it is made more difficult as the feeder runs about 500 metres in from, and is notvisible from the road due to high hedges. There is no easy resolution to this, theplacement of feeders alongside the road can generate hazards but it does make faultlocation easier.

Other Issues

6.2.10 Planned outages as a proportion of the total CMOS reduced significantly over the periodinvestigated. This is typical and reflects the increased use of live line techniques formaintenance and an increasing focus on customer requirements.

6.2.11 Rating. The feeder cannot be used as a backup supply for the TRG003 load due to the50oC thermal rating of the feeder south of the Terang zone substation. Plans are welladvanced to uprate the section of the feeder close to the zone substation to 65oC toenable the feeder to reinforce TRG003. This will be achieved with additional clearanceby retensioning and, where necessary, additional poles, reconductoring will not berequired. This is a low cost activity, which will improve the reliability of TRG003 but haveminimal effect on TRG005.

6.2.12 Operation. There are two autoreclosers and one sectionaliser. There are four normallyopen interties, one with TRG004 and three with TRG003. The two autoreclosers and thesectionaliser are currently remote controlled as is one of the three open TRG003interties. Terang zone substation is not yet remote controlled but circuit breakers can beoperated manually by GPU Powernet staff based at the nearby Terang Terminal Station.This is a less than satisfactory arrangement; the introduction of the SCADA (SystemControl and Data Acquisition) system to Terang should be given further consideration.


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6.2.13 Ballarat North BAN008

SAIDI SAIFI CAIDI Planned CMOS MVA Maintenance

1997 680 6.3 108 7.2% 8.7 $343,000

1998 357 5.4 66 2.8% 9.0 $191,000

1999 1,206 8.5 142 2.0% 9.8 $171,000

6.2.14 BAN008 is a long rural feeder supplying Daylesford, an increasingly popular holiday areanorth east of Ballarat. The town of Daylesford is surrounded by “rural residential” lots ina heavily treed environment. Between Ballarat and Daylesford, the feeder supplies openfarming country with a large number of irrigation ponds. Consequently, the bulk of theload and customer numbers are concentrated more than half the route length away fromthe zone substation.

6.2.15 Trees in the area are mainly of a “stringy bark” variety and field staff believe that barkcontributes significantly to faults on the feeder, especially in areas exposed to theprevailing northerly winds. This is not apparent from an analysis of the fault statistics.Possums and birds are also a potential threat to supply quality in the treed areas whilstswans, which frequent the water areas, are prone to fly into lines and cause considerabledamage.

6.2.16 The feeder comprises a mix of 3-phase and single-phase together with some 3-phasesingle core underground cable and SWER. The feeder is equipped with a number ofremote and automatic sectioning devices. These ACR’s are equipped with electronicprotection and control including sensitive earth fault protection.

6.2.17 A number of proposals for the construction of an alternate supply to Daylesford havebeen discussed. The latest proposal involves the construction of approximately 8km andthe upgrading of about 20km of line. If this plan materialises it should lead to significantimprovements in feeder performance.

6.2.18 Not all line equipment is in accordance with the latest standards. Significant progress hasbeen made with the implementation of pole fire mitigation measures (replacement ofwood crossarm/pin insulators with steel crossarm/line-post insulators) and the installationof bird guards of various types where appropriate.

6.2.19 Surge arrestor earth bonding is not in accordance with the latest standards in manycases and arrestor effectiveness is therefore sub-optimal. Surge arrestors are fitted to alltransformers and cable terminations except single-phase transformers of less than 25kVA capacity. This is a Powercor policy; decision based on assessed cost effectiveness.

6.2.20 Fault crews based in Ballarat undertake fault response on the feeders. This can result inresponse delays of over half an hour due to the travelling time required.

6.2.21 The Lyonsville ACR has sometimes operated incorrectly, and after a fault, it cansometimes be difficult to get the feeder ACR’s to reclose due to high pickup current. It isthought that charging currents from an adjacent 10 km of 22 kV underground reticulationdischarging through the ACR could be a contributing factor to the incorrect ACRoperation.

6.2.22 The above can result in parts of the feeder being subjected to extended outages since, ifan incorrect protection operation indicates that a permanent fault exists, it is necessary topatrol the whole feeder before attempting a further reclose. This can take 3-4 hours ifthe incident occurs during daylight and 6 hours or more if the incident occurs at night.

6.2.23 The major cause of faults on this feeder is lightning, which accounted for 33% of the totalunplanned CMOS over the three-year period. January 1999 was a particularly bad whentwo storms battered the area in the final two weeks of the month (the Australia Daystorms). Fault statistics show a CMOS of 2,646,140 over this two-week period. This


Doc No.71321 19/09/00 Page 48

represents 54% of the total unplanned CMOS for the 1999 and more than the totalCMOS for both 1997 and 1998. These storms were the main reason for the poorreliability of the feeder in 1999.

6.2.24 The major problem was a fault that occurred at 12.23 am, that left the whole feederdownstream of the Blampied ACR off supply for almost 9 hours. It is understood that, inthis case, fault crew was unable to get the ACR back into service due to the large take-up load on the feeder. A lot of time was spent searching for a fault that was never found.A more formalised fault restoration procedure may have alleviated the situation.

6.2.25 While the above fault was being attended to, there were two other faults on the feeder,back towards the zone substation, affecting 118 customers. These customers were leftoff for up to 15 hours, presumably because of the resources that were going into locatingand restoring the main fault.

6.2.26 This category accounted for 29% of the CMOS in 1997. This was almost entirely due toa fault at the Clarke’s Hill regulator cutting supply to most of the feeder (3938 customers)for over three hours. It is not at all clear how a regulator fault can be categorised as a“customer side” incident and it is of concern if a major event such as this is wronglycategorised.

6.2.27 This was a significant cause of outage in 1997, causing 26% of the unplanned feederCMOS for that year in 7 separate incidents. Fault duration’s ranged from 69 minutes to335 minutes with six of the seven incidents causing outages of over 145 minutesduration. Six of the incidents occurred over the period of 12-20 July 1997.

6.2.28 For this feeder, it would seem that the most effective short term measure to improvereliability would be to develop firm procedures for fault restoration following feeder faultswhere the fault cause or location is unknown. These should give firm guidelines forsectionalising and reclosing to more quickly identify a fault location. Feeder specificguidelines for restoring supply after an extended outage would also assist.

6.2.29 Horsham HMS002


1997 659 5.25 126 8.3% 5.0 $80,000

1998 1,155 12.3 94 3.2% 5.2 $119,000

1999 246 3.15 78 5.8% 4.2 $41,000

6.2.30 HSM002 is a long rural feeder 1,524 km in length that runs mainly to the west ofHorsham. A rural load centre, Edenhope, at the west end of the feeder imposes asignificant urban load towards the end of the feeder. The feeder supplies mainly grainand grazing with some dairy. Beyond Edenhope, the feeder has several long spursheading towards the boarder with South Australia. The feeder also supplies part of thenorth western Grampians from a line connected to the Horsham end of the feeder.

6.2.31 The feeder comprises two separate sectors; each protected by its own ACR locatedabout 2 km from the Horsham zone substation. The first sector supplies Edenhope via a66 kV line, currently being operated at 22 kV. Approximately 60% of the customers areconnected to this Edenhope sector.

6.2.32 Apart from some urban load at the Horsham end, this line operates as a subtransmissioncircuit, with no rural customers connected, until about 20 km from Edenhope. It hasbeen built to 66 kV construction to facilitate the eventual construction of a new zonesubstation at Edenhope, should the load grow sufficiently to warrant this.

6.2.33 There are two regulators between Horsham and Edenhope. While there are threeremotely operated switches and one remote auto-recloser at Edenhope and beyond,communications are marginal, which means that the switches often have to be operatedmanually. Edenhope can also be supplied by an alternative feed from HSM004 although


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this is seldom used due to loading constraints. Work that may have alleviated thisconstraint had been underway to reconductor key sections of HSM004, but this projecthas now been discontinued.

6.2.34 The second sector supplies Balmoral and Brimpaen, on the western side of theGrampians.

6.2.35 A pole fire mitigation program ($700,000) has been underway for the last 3 years totarget areas where pole fires have impacted backbone reliability. This work is scheduledfor completion this year.

6.2.36 Fault repairs at the Horsham end are provided from the Horsham depot. There is also aLocal Service Agent at Edenhope who can undertake limited fault repairs and localswitching. However major faults, such as a pole or transformer replacement atEdenhope and beyond have to be serviced from Horsham and the response times canbe slow due to the distances involved.

6.2.37 The major problem on this feeder over the three year review period has been lightningwhich accounts for 41% of the total CMOS. 1998 was a particularly bad year withlightning causing more customer minutes off supply than recorded from all causes in1997 and 1999. Major lightning faults generally trip the Edenhope ACR – lightning doesnot seem to be as significant a problem on the Balmoral sector.

6.2.38 Pollution and pole fires are also significant fault initiators, and together were responsiblefor 16% of the CMOS over the review period. Fault statistics indicate that these faultswere less of a problem in 1999, which could be a result of the pole fire mitigationstrategy.

6.3 CHARACTERISTICS OF SHORT RURAL FEEDERS SELECTED

Woodend WND012


1997 88 1.66 53 52.2% 9.3 $67,000

1998 413 4.18 123 15.7% 9.6 $109,000

1999 986 11.01 89 9.2% 10.1 $124,000

6.3.1 WND012 traverses and supplies part of the CBD area of Woodend town, a wealthyMelbourne commuter location. Past the town centre, the feeder supplies a housing areawith large houses set amongst trees.

6.3.2 Many of Woodend feeders are heavily loaded and it is not easy to transfer load betweenthem. To alleviate this problem, WND021 was commissioned in June 1999 and tookcustomers and load from WND012. A new cable was run from Woodend zonesubstation to pole 21 on Tylden Rd with load in southern area of Woodend transferred tothis new feeder. There is a lot of in-fill housing being developed in this thriving smalltown.

6.3.3 The load appears to be of the greatest concentration in the 25 to 50% section of thefeeder length, although a significant number of residential consumers are attached in thefirst 25% of the feeder. A spur from the end of the feeder supplies the small hamlet ofHesket.

6.3.4 The feeder leaves the relatively new indoor Woodend Zone Substation with a 0.5kmlength of cable, before running down through an ornamental wooded area. The feederafter leaving the town is also largely in a small forest area.


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6.3.5 Alternative, manually operated feeds are installed to WND013 near the zone substationand to WND022 just prior to the CBD area. A remote operated switch allows connectionof WND012 with WND021. Woodend zone substation also has full remote control.

6.3.6 A mixture of new concrete and some very old slender hardwood poles are in evidence.Some hardwood poles have been treated with tar. Often old crossarms have been re-fitted to new concrete poles.

6.3.7 Powercor are rebuilding the section of WND013 that is adjacent to end of WND012(Hesket Rd). Once this three-phase reconstruction is completed, WND012 will be used tosupply southern section of Romsey Town. However, WND012 reliability will not bereduced due to existence of ACR on Mt. Macedon Rd. Budgets are approved forcarrying out this work.

6.3.8 There are problems with load profiles in Woodend as there is no gas available. On thetown feeders, there are very large 1.30am peak demands due to “slab” heating.Conversely, at Kyneton the maximum demand is in the daytime since gas is availableand a local factory strongly influences the demand. Powercor are examining relocatingload between feeders and adjusting timers for “slab” heating to alleviate peak demandproblems.

6.3.9 Fault response is provided to WND012 using Powercor staff located at Kyneton.

6.3.10 Malfunctions featured as the major “cause” of outages over the review period. For manysuch interruptions, the reason was fuse failure. However on 22nd January 1999 thewhole feeder tripped out with the cause given as malfunction and the reason “burnt”.There was an unexplained circuit breaker operation on 29th July 1999 and 2 days later;another malfunction took out the whole feeder with the reason given as “broken”. Thesethree faults together caused 77% of the unplanned CMOS in 1999 and were the majorreason for the poor feeder reliability last year.

6.3.11 Possums would appear to the most prevalent problem on the feeder and wereresponsible for 35% of the total CMOS over the review period. This included two feederoutages in April 1998, which together caused 63% of the total 1998 CMOS. Frequentpossum initiated faults occurred throughout the review period.

6.3.12 Woodend is a tree hazard area with high fire risk status due to its proximity to forest area.There are problems cutting trees, as negotiation is difficult with many customers. Somehave been known to be prepared to fund undergrounding instead of Powercor installing anew overhead 22 kV line. Over the review period tree related incidents caused 12% ofthe total CMOS. This included a single feeder fault in October 1998 that was responsiblefor 19% of the 1998 CMOS.

Terang TRG001


1997 998 5.9 169 11.9% 7.5 $67,000

1998 321 1.8 178 17.0% 7.8 $75,000

1999 667 3.6 185 12.1% 2.6 $57,000

6.3.13 TRG001 is a short rural feeder supplying generally flat, open dairying country. It used tosupply the Bonlac dairy factory in Cobden but this situation changed with thecommissioning of the Cobden zone substation in early 1999. This accounts for thereduction in load in 1999.

6.3.14 The feeder generally runs along the road, although isolated sections run across country.


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6.3.15 There are no remote controlled switches on the feeder. There is an ACR close to thezone substation on the main feeder backbone that was originally installed to preventfaults on the rural part of the feeder affecting the supply to the Bonlac factory. With thereconfiguration following the commissioning of the Cobden substation, this ACR nowserves no purpose and should be relocated.

6.3.16 There are two interconnections with other feeders. The northern part of the feeder canbe supplied from TRG002 while the south and east can be supplied from CDN006.

6.3.17 There are three sectionalising switches on the feeder. The gas switch (Raceway 5) atthe beginning of the Dalvui Lane spur would seem to serve no real function and might bebetter replaced by fuses.

6.3.18 Terang is a lightning prone area and is subject to severe lightning storms betweenJanuary and March. Lightning (or storm damage) is the predominant cause of faults onthis feeder both in terms of CMOS and number of interruptions. This was responsible for47% of the total CMOS over the review period and 24% of the interruptions. January1997 and January 1999 were particularly bad months.

6.3.19 A “malfunction” in on 1st March 1999 caused a total CMOS of 154,878 or 62% of theoverall 1999 CMOS. The cause is given as “cut” but no further information is availableon the cause of this fault.

6.3.20 Due to the major feeder reconfiguration in early 1999, comparison of the 1999 result withearlier data may not be valid. Nevertheless, given that this feeder is now relatively short,and that lighting will continue to be a major fault initiator, it would be a good choice werePowercor to trial any revised strategy for the mitigation of lightning faults.

Shepparton STN003


1997 64 0.65 98 25% 6.3 $39,000

1998 267 2.84 94 1% 3.1 $42,000

1999 695 4.44 156 69% 3.1 $72,000

6.3.21 STN003 is a short rural feeder 40 km in length and runs through the south west urbanarea of Shepparton and then into rural Shepparton. Businesses in the Shepparton areaare mainly orchards, dairy farming and cropping. STN003 has 782 customers, many ofwhom are on the urban section of the feeder. The feeder then progresses through orchidareas and into sheep and cropping together with a minor rural town.

6.3.22 The main work done in recent years has been to underground the feeder where it exitsSTN zone substation. There are no plans for enhancement work in the next 5 years. Asthere is plenty of capacity in main backbone of feeder.

6.3.23 Feeder performance has deteriorated each year of the review period. The deteriorationin 1999 is due only to the large amount of planned work undertaken on the feeder.

6.3.24 STN003 fault calls are responded to by staff from Shepparton Depot.

6.3.25 The major cause of unplanned outages on this feeder is birds, which accounted for 41%of the total unplanned CMOS over the review period. Bird proofing has been carried outin the fire declared area but most of STN003 is not in a fire declared area and this work isnot yet completed in the declared non fire area.

6.3.26 Possums are also a significant problem. Lightning is also a problem, mainly becauselightning faults tend to have a longer restoration time than other incidents. This ispossibly because fault staff are busy during storm periods, resulting in delayed responsetimes.


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Warun Ponds WPD014


1997 142 1.75 81 14.8% 9.5 $85,000

1998 501 7.48 67 31.1% 7.6 $74,000

1999 229 3.27 70 17.8% 7.7 $88,000

6.3.27 WPD014 is a 182 km short rural feeder that supplies open pastoral land between WarunPonds and the south coast, as well as parts of Anglesea, Airey’s Inlet and Fairhaven atthe eastern end of the Great Ocean Rd. These are coastal holiday resorts withsignificant population and load increases at weekends and holidays.

6.3.28 Load on the feeder is primarily agricultural and residential. Other loads include waterand sewage pumping stations around Anglesea. The feeder also provides a backupsupply to Alcoa’s Anglesea power station.

6.3.29 The northern end of the feeder supplies flat pastoral country. Along the coast, the terrainis hilly and heavily treed. Many of the spans are long, extending from ridge to ridge, withthe longest supported by lattice steel tower structures. The feeder is subject to heavysalt pollution, particularly during southerly winds. Lightning can be a problem.

6.3.30 Close to Warun Ponds zone substation there is an open point interconnection toWPD031. There are two interconnection points to WPD022, one outside Torquay andone in Anglesea. The end of the feeder connects with CLC005 on the eastern outskirtsof Lorne. It is unlikely, however, that the feeder has sufficient capacity to carry Lorneduring periods of peak load.

6.3.31 There is a regulator close to the Anglesea power station and an ACR between Angleseaand Airey’s Inlet. Remote control switches are located on both interconnections withWPD022 and at Fairhaven.

6.3.32 There are no known current plans to reinforce this feeder. The feeder used to supplymuch of Anglsea but this was transferred to WPD022 in 1998.

6.3.33 Of particular note on this feeder is the use of the 220kV tower structures of Alcoa’s 220kV line to support a section of the feeder. This single circuit line is built on double circuittowers and the spare circuit position carries the backbone of WPD014 between HendyMain Rd and Tower 07 at the Storage Basin.

6.3.34 Other unusual construction features are the use of lattice steel towers and long spansbetween Fairhaven and Lorne, the use of 66 kV pin insulators in coastal areas and theuse of covered conductors in selected areas around Lorne. It is understood that thecovered conductors were put in as a pilot scheme to reduce clearance requirements inheavily treed areas. HV ABC has now superseded this form of construction.

6.3.35 Most of the structures on the feeder are of the old standard with wooden crossarms andpin insulators. It is estimated that only about 20% of the feeder has been converted tothe new fire resistant steel crossarm, cruciform design. A greater percentage ofstructures close to the coast have been uprated for the coastal environment, either byusing 66 kV insulators or cruciforms. Nevertheless, a significant number of non-fireresistant coastal structures with wooden crossarms and 22 kV pin insulators were noted.

6.3.36 Management of the feeder is undertaken from the Geelong depot. This is located at thenorthern end of the feeder, away from the coast, where faults are more prevalent. Thedrive from Geelong to Lorne would take around an hour in moderate traffic. Duringholiday periods, the drive would be longer, due to the traffic generated by the large influxof holidaymakers.


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6.3.37 Planned CMOS was a significant contribution to total CMOS on this feeder throughoutthe review period, particularly in 1998 when planned outages accounted for over 30% oftotal CMOS.

6.3.38 Possums were a particularly troublesome fault cause accounting for 56 outages or 14%of the total outages over the review period. Most of these faults were heavily forestedtransformer faults in the heavily forested coastal area. Birds were also a troublesomefault cause, again causing transformer faults in the heavily treed coastal area. Togetherbirds and possums caused 27% of all CMOS over the review period.

6.3.39 Tree related faults caused only 2% of the outages during the review period although it isunderstood that tree clearing is an ongoing problem in the coastal area.

6.3.40 Pollution is the second highest cause of minutes off supply. Assuming the cause “burnt”in this category indicates a pole fire there were three pole fires on this feeder in 1998 andtwo in 1999, all in the first few months of the year.

6.3.41 In January 2000, there were 18 faults on this feeder causing extended outages and inFebruary, there were 13. The total CMOS caused by these faults is estimated to begreater than the total unplanned CMOS for the whole of 1998 and almost twice the totalCMOS for 1999. 49% of this CMOS was due to faults categorised as pollution or fire.This analysis excludes one fault reported to the ORG as having 18 customers off supplyfor a period of almost four days.

Ballarat North BAN015


1997 72 1.42 51 11.0% 6.5 $99,000

1998 365 6.91 53 0.7% 6.7 $71,000

1999 74 1.20 62 4.0% 6.9 $77,000

6.3.42 BAN015 supplies predominantly residential properties in and on the outskirts of Ballarat.The feeder follows town roads for much of its 51 km length and most of the 3492customers live in an urban area. Nevertheless, some ends of the feeder supply ruralload on the outskirts of Ballarat.

6.3.43 The feeder is close to the Ballarat depot and this greatly assists fault response.Furthermore, as much of the feeder runs through the Ballarat urban area, many faultlocations are reported by the public.

6.3.44 The urban nature of this feeder is illustrated by the eight normally open interconnectionsavailable. Three ties are available with BAN007, two with BAS023, and three withBAN011. However, the tie at Neerina with BAN011 has limited capacity because of thelight conductor. There are ten sectionalising switches on the feeder backbone, giving alarge number of different switching zones.

6.3.45 Bird proofing and pole top fire mitigation measures were well advanced, if not completed.

6.3.46 However, the CAIDI was consistently about an hour for each year of the three-yearperiod of interest. This seems long, given the accessibility of the feeder and itscloseness to the Ballarat depot. It appears that, in spite of many opportunities forrestoring supply to unaffected customers, this may not always be done.

6.3.47 Planned outages accounted for 11% of CMOS in 1997 and 4% in 1999.

6.3.48 There appears to have been a major problem with the zone substation circuit breaker inearly August 1998. There were five unexplained circuit breaker trippings between 29th

July 1998 and 6th August 1998, including three trippings in the one day on 2nd August1998. The final tripping on 6th August 1998 affected only about 45% of the customers


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normally on the feeder, indicating that by that time Powercor had become concernedenough about the problem to transfer some customers on to adjacent feeders.

6.3.49 In total, these events accounted for 62% of the unplanned CMOS in 1998 and 45% of theCMOS over the three-year review period. They were the main reason for the poor 1998performance.

6.3.50 Four vehicle impacts over the review period caused 21% of the CMOS. Most of theseincidents occurred in the early morning.

6.3.51 The fault records show a 451 minute feeder outage on 19 February 1999. This oneincident caused 76% of the unplanned CMOS on the feeder in 1999.

6.3.52 Fault records show a single incident attributed to pollution on 2 August 1998 whichcaused a CMOS of 278752 or 22% of the 1998 CMOS. The reason given is “nodamage”. In fact, this fault is probably wrongly categorised as it occurred on the sameday as the “malfunction” incidents described above.

6.3.53 Animals, probably possums, caused a total CMOS of 54017, or 3% of the CMOS overthe review period. There were 16 separate interruptions, most of which involvedtransformers.

6.4 CHARACTERISTICS OF URBAN FEEDERS SELECTED

Sunshine SU005


1997 651 8.7 75 10.4% 10.6 $140,000

1998 1018 20.1 52 0.7% 11.1 $149,000

1999 857 10.7 80 0.2% 12.1 $138,000

6.4.1 SU005 is an urban feeder supplying a mixture of loads. Close to the zone substation itsupplies older urban residential and industrial properties and whereas further out itsupplies newer residential and industrial areas around Laverton North, with significantload growth. Therefore, most of the load is located in the developing areas close to theend of the feeder.

6.4.2 Much of the feeder traverses open rural land, generally as it moves from onedevelopment to the next. Some of the rural parts of the feeder cross open country andare not located beside a road. Close to the substation, the feeder runs alongside a longstraight road with a bad reputation for speeding traffic. The poles are placed very closeto the carriageway with the result that vehicle impact is a significant risk. There havebeen three vehicle impact faults over the last three years.

6.4.3 The feeder provides a standby supply to the Orica plant (formerly ICI), normally fed fromSU004. Alternate supplies from SU008 are also available near the subsidiary ICI supplyin Foley’s Rd and in the Laverton North area.

6.4.4 There are three remotely controlled switches on the feeder. Three of these switchesallow the feeder to form a back up supply to ICI. This is done by off loading the majorityof the feeder load onto SU008 at Foley’s Rd and by using the lines close to the Sunshinezone substation to feed Orica directly. This transfer can be implemented remotely.Industrial loads supplied include the Boral quarry and a new women’s prison in theRiding Boundary area as well as new industrial developments near Laverton North.

6.4.5 The feeder topography will change significantly once the new Laverton 22 kV substationis completed. The rapidly developing loads at the Laverton end of the feeder will besupplied from this new substation. Therefore, SU005 is likely to become a shorterfeeder, primarily supplying urban loads closer to the Sunshine area. Plans for this


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substation are well advanced and are currently being considered by the capitalexpenditure committee within Powercor.

6.4.6 Close to the Sunshine substation, the feeder is constructed to the older SEC design,utilising wooden crossarms and pin insulators. Further out a range of other constructionsare evident, reflecting changes in SEC standards and a gradual extension of areascovered by the feeder.

6.4.7 A number of slack spans were noted which are potential fault zones due to conductorclashing. Surge arrestors; were generally mounted to the old standard, well above thetransformer, rather than on the tank.

6.4.8 A modern ground mounted substation supplying an industrial park was inspected. Therewas no vermin proofing and a dead rabbit was found inside the enclosure. A furtherconcern was an apparent lack of ventilation, which could create problems in situationswhere such substations were fully loaded on a hot Melbourne summer day.

6.4.9 The Sunshine zone substation is not remotely controlled.

6.4.10 There used to be a field office at Sunshine but this has closed in and all field staff for thearea, including fault crews, are now based at Werribee. This is likely to have impactedresponse times, particularly during peak hours.

6.4.11 Planned outages had a significant influence on feeder performance in 1997 when theyconstituted almost 11% of SAIDI. It is interesting to note that, in spite of this, total SAIDIfor 1997 was less than unplanned SAIDI for both 1998 and 1999.

6.4.12 Three-recorded vehicle impacts caused 15% of the unplanned CMOS over the three-year period. Staff familiar with this feeder all said it was notorious for vehicle impactsand commented that the recorded faults due to this caused appeared under reported.The feeder runs along Tilburn Rd, Robinson’s Rd and Mt. Derricott Station Rd, all locallyknown as racetracks. In many cases the poles were close to the edge of thecarriageway, possibly because of road widening after the line had been originallyinstalled.

6.4.13 Birds resulted in 13 outages, in 1998 and 1999 in total causing 14% of three yearlyunplanned CMOS. Four were feeder faults and seven were substation faults. Bird faultson this feeder are localised. The substation faults were all near the Boral Quarry whilethe feeder faults are generally on the one pole. The problem is crows, which often grouptogether in the one place. Field staff advises the bird problems have continued into 2000and that the bird proofing of the Boral transformers is being reviewed.

6.4.14 Two incidents of conductor clashing caused feeder faults and a total of 10% of three yearunplanned CMOS. A number of slack spans were noted during the feeder inspection.

6.4.15 Two outages in 1999 were attributed to lightning and caused 3% of three yearlyunplanned CMOS. One incident caused a 2 hour unplanned feeder fault while thesecond caused a substation feeder over 400 customers to be off for 7 hours. The reasonfor the long restoration period in the second outage is not known. It can be assumed thatthe transformer required replacement but the fault statistics say only that a fuseoperated.

6.4.16 There were four tree related interruptions, causing 1.5% of the three year unplannedCMOS.

6.4.17 Overall, there were nine feeder faults over the three-year period, accounting for 45% ofunplanned CMOS. The actual situation may well have been worse given that customernumbers are suspect. The faults were attributed to a variety of causes.

6.4.18 Feeder records show the total customers in 1997 as 2411 and in 1998 as 493. Over thistime, there has been no significant change in load or feeder configuration. Powercor hasadvised that the 1997 figure is incorrect and that the correct figure is about 500. We


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have concerns about the accuracy of customer numbers on this feeder and, based onour inspection believe that 500 may be too low. Fault records show feeder faults with thenumber of customers affected varying between 5025, 2425 and 509. Either there havebeen major changes in the configuration of this feeder, which understand not to be thecase, or the customer records are inaccurate. In this case, the reported SAIDI wouldalso be inaccurate.

Geelong GL022


1997 32 0.27 119 0.1% 5.4 $8,000

1998 76 0.69 110 9.1% $43,000

1999 273 3.1 88 2.2% 5.4 $29,000

6.4.19 This is a short, heavily loaded urban feeder supplying parts of Geelong. It appears to beoperating in a relatively stable environment and is not considered a problem feeder bythe depot staff. It was noted that vegetation control was a problem with trees growingthrough or very close to mainly low voltage conductors, particularly in the Newtown area.

6.4.20 There are alternate feeds available from adjacent feeders, including GL011, GL012, andGCY014. None of these is capacity constrained. The feeder configuration has remainedunchanged over the last five years.

6.4.21 The feeder is generally constructed to old SECV design standards with wooden crossarms and pin insulators. Less progress upgrading the design has been made than inother areas and less than 20% of the feeder has appropriate pole fire mitigationmeasures.

6.4.22 Problems noted on inspection were: -

1 Transformer surge arrestor positions were sub-optimal

2 A number of slack spans exist with increased risk of conductor clashing in high winds

3 A number of structures require bird proofing

4 Burning through the stirrups of hot line clamps is a problem because of the higherloads on the feeder

6.4.23 Corrosion/infestation faults are generally single premise outages for which “burnt” or“broken” is given as the reason. The same applies to most faults classified as loose orpoor connection and also many classified as malfunction (see below). Faults classifiedas electrical overload generally have a blown fuse.

6.4.24 Fault records for this feeder in January and February 2000 show good reliability with nofaults recorded in January and only three in February. The February faults appeared tobe transformer problems and caused an estimated 72,163 CMOS.

6.4.25 A feeder fault on 19 June 1999 caused a total CMOS of 596,100. This was 64% of thetotal CMOS on the feeder for 1999 and 47% of the CMOS over the three-year reviewperiod. The fault is classified as “malfunction” and the reason given is “CB operation”. Itis understood that there was a problem with the circuit breaker protection at the zonesubstation.

6.4.26 Most of the faults experienced appear to be age related. This is consistent with theinspection of the feeder. Conductor clashing is another significant fault cause,accounting for 7% of the total CMOS over the review period.


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Sunshine SU004


1997 205 2.6 79 46.9% 8.5 $1,000

1998 62 0.4 153 0% $0

1999 93 0.8 116 33.7% 6.4 $1,000

6.4.27 SU004 is a short urban feeder primarily supplying the Orica (formerly ICI) plant. It alsosupplies urban residential load between the power station and the plant.

6.4.28 The feeder covers flat urban terrain and is readily accessible. A short section of the linepasses through an open reserve and the line is underground where it crosses thewestern freeway. It is in a non fire-risk area and vegetation control is a problem,particularly for the overhead low voltage network. It can be fully supplied from SU005with no apparent capacity constraints.

6.4.29 The maximum demand at ICI is 195 A or 7.5 MVA and the plant therefore consumesalmost 90% of the load on the feeder. The plant demand is falling and this is reflected infeeder load statistics.

6.4.30 A few slack spans were noted causing a risk of conductor clashing. Transformer surgearrestors were generally mounted at the old sub-optimal standard.

6.4.31 The Sunshine zone substation is not remotely controlled. There used to be a field officeat Sunshine but this has now closed in and all field staff for the area, including faultcrews, are now located at Werribee. This is likely to have impacted response times,particularly during peak hours. Planned outages had a significant influence on feederperformance in 1997 and 1999. There were no planned outages in 1998.

6.4.32 The major cause of faults on this feeder is lightning, which accounted for 27% of the totalunplanned CMOS over the three-year period. This was entirely due to an incident inOctober 1997, which took out the whole feeder for 61 minutes. Fault statistics indicatethat a fire was also involved, which may have been the reason for the extended outage.Had this incident not occurred, 1997 SAIDI would have been reduced by 57% and wouldhave been well below the level for 1998 and 1999.

6.4.33 Electrical overload accounted for 14% of the CMOS for the over the three year period.Malfunction was another problem resulting in 11% of the faults. Fault frequency was lowin 1997 and somewhat higher in 1998 and 1999.

6.4.34 These two categories have been grouped together since both are generally caused byfuse operation. We have not been able to locate any guidelines for categorising faults ofthese nature and suspect that both categories include fuse operations where the causeis unknown. It is understood fault categories are entered on the basis of these reportsfrom the field. We were told that in many cases, the cause of faults was not discussed inany detail with the controllers who closed off the incident reports.

6.4.35 Loose/poor connections caused 14% of the CMOS over the three-year period of interest.All but one of these were single premise outages. In 1998, a substation was out for 138minutes and this one fault caused 93% of the total CMOS due to this category.

6.4.36 Birds caused two faults, one in 1998 and another in 1999. One was a premise outageand the second a substation, indicating that birds are not a problem on the HV lines.Birds caused 12% of the total CMOS over the three-year period.

6.4.37 Tree related problems caused 15% of the CMOS over the review period. However, therewere only two interruptions, one in 1997 that took out the whole feeder and one in 1999,which affected a single substation, indicating that the problem affected the low voltagelines only. The 1997 incident was for tree clearing, but is categorised as an unplannedrather than a planned outage.


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6.4.38 During the feeder inspection, it was noted that a number of trees were growing close to,or through, the lines, particularly the low voltage overhead network. Sunshine is a nonfire-risk area, with tree clearing being the responsibility of the local council. Clearly,vegetation control in no fire risk areas is of less importance than control in fire risk areas.

6.4.39 There were only two feeder faults over the three-year period. Taken together, theseaccounted for 40% of total unplanned CMOS.


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7 ASSET MANAGEMENT

KEY POINTS

Maintenance practices are sub optimal. Reliability Centred Maintenance (RCM) hasbeen adopted in principle, only the condition-based component has been adopted. The“reliability” functionality is only now being implemented as Powercor move to morelocation dependent maintenance.

Section 7.2

Demand side management could lead to greater benefits. Powercor areimplementing demand side management to reduce the need for feeder enhancements,but this could also defer capital expenditure to a greater extent than recognised inPowercor’s pricing submission.

Section 7.1

Feeders do not have a regional sponsor. Powercor’s process structure has thepotential for business efficiencies but requires good communications. There arefunctional centres of excellence but there is no regional presence with a comprehensiveview of a feeder.

Section 7.2

Risk management strategies are incomplete. No documented strategy was providedby Powercor to demonstrate they had appropriate risk management strategies for theirnetwork business. Adoption of scenario planning could result in more robust assetmanagement together with ensuring an appropriate risk management regime is in place.

Section 7.2

Expenditure per customer is increasing. The rate of increase is greater for customersconnected to long rural feeders than for customers connected to an urban or short ruralfeeders. Furthermore Powercor is currently spending over twice as much per customeron long rural feeders than it is on short rural and urban feeders.

Section 7.3

7.1 PRINCIPLES OF ASSET MANAGEMENT

7.1.1 The key principle of asset management is to ensure that the condition of the assets isbeing effectively monitored, and that the assets are being maintained and developed toprovide appropriate levels of service to meet customer needs and stakeholderexpectations.

7.1.2 This requires that there is a good understanding of customer needs. In the case ofPowercor, the customer also includes the Office, which has a statutory obligation toconsider the needs of the customer.

7.1.3 In determining what the appropriate maintenance strategy should be, the performance ofthe assets over time needs to be considered. There will always be a trade off betweenmaintaining or replacing an asset to ensure the appropriate service level and theappropriate timing of particular asset management activities.


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7.1.4 The linkages between asset management output performance, system adequacy,system design, asset condition and operating factors are shown in Figure 7.1.1.

Figure 7.1.1 Asset Management Linkages

Customer Service,Business & Legal

Requirements

Asset/SystemDesign

Design Polices &Standards- Security Criteria- Supply Quality- Equipment Design

AssetCondition

Defects Criteria/Conditions Indicators- Corrosion- Wood Pole Rot- Insulator Wear etc- Number of Operations

SystemAdequacy

Future Requirments

Output Performance Internal Performance Determined by Asset Management Activity

System & LocalOperations

Operating Policies &Standards- Control- Dispatch

Indicators

Equipment Fault/Failure Report- Poles/hardware- Insulators- CBs- Transformers- Protection

Circuit Availabilities

Human Errors

Restoration Times

Losses

Costs

Indicators

Customer Service

Accidents

Environment Incidents

Transmission Costs

Asset/SystemDevelopments eg- Asset Rationalisation- Asset Creation- Asset Enhancement

Operations

Asset Maintenance eg- Vegetation/Buildings- Patrols & Inspections- Testing (eg gas in oil,

other non-invasive)- One-off Repairs/Defects

7.1.5 An example of an appropriate asset management strategy is Powercor’s approach tofeeder capacity problems. In reviewing zone substation planning studies associated withthe feeders under investigation, it was noted in a number of cases that Powercor have asignificant problem with capacity requirements driven by night peak demands. Thegraph in Figure 7.1.2 shows the daily load cure for HSM002 feeder22 (one of the feedersselected for investigation) at Horsham zone substation.

7.1.6 On HSM002, the load peaks in the early hours of the morning are a consequence ofwater heating load being restored. In other situations, such as for Woodend zonesubstation, it is understood that significant night peaks are being strongly influenced bythe switching on of “slab” storage heating. Such high early morning peaks appear to betypical in areas where there is no local gas reticulation and electricity is used for waterand storage heating.

7.1.7 In order to reduce these high peak load demands, Powercor are adopting demand sidemanagement strategies. The intended approach is to adjust load control time clocks tosmooth out these high peaks.

22 Document P119 Horsham ZSS Area Planning Report


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Figure 7.1.2 HSM002 Load Profile

0

2 0

4 0

6 0

8 0

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T i m e

Loa

d cu

rren

t in

Am

ps

H S M 2

7.1.8 The implementation of demand side management, where Powercor is able to defer majorcapital expenditure by modifying customer demand, is an example of an assetmanagement strategy that adopts “non asset” solutions.

7.1.9 It has not been possible to establish the full impact of demand side management on thefuture capital expenditure program. Powercor note in their pricing submission that theyare examining demand side management as an alternative to enhancement work, but donot quantify any direct benefits. In several of the zone substation planning studiesexamined as part of this investigation, demand side management was considered to be astrong option for capital expenditure deferral. This could result in the benefits Powercor-wide being greater than have been quantified by Powercor and could defer capitalexpenditure proposed in their pricing submission. There is some evidence that Powercorare promoting photovoltaics, but overall there appears to be no strategy to developembedded generation as a cost effective means to minimise expenditure on thedistribution network and raise reliability and capacity.

7.2 ASSET MANAGEMENT STRATEGIES

7.2.1 Powercor’s asset management strategy is23,24

“Asset Management is the structured and systematic approach to acquiring,managing, maintaining and disposing of assets so that Powercor’s customer andbusiness needs are met, and its obligations to shareholders, the community,government and regulator are satisfied”

7.2.2 Powercor state that asset management will include: -

• Reducing the need for new assets by adoption of cost –effective “non asset” solutions

• Ensuring that existing assets are effectively and efficiently utilised

• Optimising total life cycle cost of assets from acquisition, operation, maintenance todisposal

• Establishing clear accountability and responsibility for assets and their performance

23 Document P22 Powercor presentation to Utilities Insurance 17 July 199824 Document P40 Powercor Asset Management Strategy


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7.2.3 The asset management strategy was developed in 1996 when an initial review wascarried out. Powercor noted that good performance was identified in asset constructionbut asset management lacked focus, with inadequate attention to life cycle costing, assetrationalising and asset performance.

7.2.4 During a second phase of the strategy development in 1997-98, reliability centredmaintenance (RCM) was used as an assessment tool, with the outputs used in theconfiguration of SAP. The approach was to carry out analysis of major equipmentgroups. The RCM approach adopted took into account function of equipment, failuremodes, failure effects, failure consequences, and preventative tasks and default actions.

7.2.5 This review, prior to the introduction of SAP, was carried out by a team of 23 people fromall parts of the business and led by an external consultant. The maintenancefrequencies for various asset types (lines/cables, transformers, circuit breakers andcontrol/protection) along with components within these were reviewed. On the basis ofthis review, rules were developed, which were incorporated into SAP.

7.2.6 This approach has gone part way to introducing RCM. The inspection frequencies forparticular assets have been formulated and fixed within SAP to give the requiredreliability for that type of equipment. However, the approach presently adopted byPowercor does not adjust inspection frequency or maintenance requirements accordingto the actual reliability being achieved for that particular component or feeder. Powercorare now moving to adopt location dependent maintenance practices.

7.2.7 It is considered that the “CM” elements of RCM have been implemented but that the “R”element is only partially implemented. This is a significant issue and produces a sub-optimal maintenance programme, which has potential consequences for reliability andexpenditure.

Asset management approach

7.2.8 In carrying out the asset management function, Powercor use a process approach. At acorporate level covering all facets of the business, the key business streams areNetworks, Powercor Services, Finance, HR/Corporate Affairs, StrategicDevelopment/Company Secretariat and Energy. Figure 7.2.1 Relationships betweenBusiness Streams summarises the relationships between these business streams25.

7.2.9 The key groupings for the Networks process streams, together with the location of therespective process stream leaders, is shown in Table 7.2.1. A process organisation hasthe potential for business efficiencies but requires good communication at all levels of theorganisation. The fact that Networks process stream leaders are dispersed throughoutthe various depots may impede this communication.

7.2.10 A consequence of this process approach is that Powercor now has functional centres ofexcellence, but does not have a regional presence with a comprehensive view of theassets in each region.

7.2.11 While Powercor has a risk assessment routine that examines the output of their reliabilityimprovement model, no documented strategy was provided by Powercor to demonstratethat they had appropriate risk management strategies for their network business. Theadoption of scenario planning would lead to more robust asset management.

25 Powercor 2001 Electricity Distribution Price Review Submission


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Figure 7.2.1 Relationships between Business Streams

Table 7.2.1 Networks Process Streams

Function Role Location of ProcessOwner

Development System planning for subtransmissionand network

Market Street

Performance Reliability, quality, outage statistics Sunshine

Maintenance Implement asset strategy, SAPcustodian, maintenance policy, bush firemitigation policy

Market Street

Connections New connections, inserting customerfuses

Bendigo

Operations Switching co-ordination, dispatch,ensuring data integrity

Market Street withsupport from Bendigo

Powercorservices and localcontractors

Carry out field work Various

Customerservices

Handling customer calls Market Street withsupport from Bendigo

Revenue Tariff setting, billing, revenue collection Market Street


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7.3 OVERALL EXPENDITURE

7.3.1 Powercor advises that budget preparation is a bottom up approach for each processstream. Macroeconomics drives customer connection budgets. System augmentation isconsidered on a terminal station basis but budgets are based on actual planned projectsevolving out of an analysis of development options.

7.3.2 Maintenance (operational) budgets are developed on a functional basis and not byfeeder or area. In developing costs for the price review, Powercor split maintenancecosts into urban, short rural and long rural by estimating functional costs for each type offeeder class. Functional areas include faults, zone substation maintenance, operations,vegetation and overhead line maintenance.

7.3.3 CAPEX is budgeted in terms of demand, replacement, and reliability improvementrelated work. CAPEX cost splits were more accurate as they were based on specificprojects that could be allocated to urban, short and long rural feeders. Powercor alsohave a better history of CAPEX costs on a feeder basis than for maintenance work.

7.3.4 In general, the budgeting process is sound as it is applied to subtransmission assets.However, Section 10 discusses a number of shortcomings in the operation of the budgetprocess in relation to distribution assets.

7.3.5 Table 7.3.1 provides an overview of the planned overall expenditure, as documented inthe price review submission, for specific asset groups, together with actual 1999 spend.

Table 7.3.1 Pricing Submission Overall Expenditure ($ 000's)

Asset Group 1999 2000 2001 2002 2003 2004 2005

Urban 11,817 14,181 15,928 17,587 16,609 17,015 16,445

Short rural 13,212 16,421 16,585 19,275 18,403 19,874 20,282

Long rural 25,971 32,154 34,535 38,569 36,430 41,075 38,986

Subtransmission

4,948 12,360 21,844 17,195 17,703 27,125 17,815

Metering 11,544 12,569 15,116 14,856 14,882 15,209 15,448

Street lighting 3,723 4,604 4,512 4,489 4,531 4,638 4,709

Total 71,215 92,289 108,520 111,971 108,558 124,936 113,685

7.3.6 Figure 7.3.1and Figure 7.3.2 show the trends in overall expenditure on a per customerand per km of feeder basis.

Figure 7.3.1 Overall Expenditure/km by Feeder Type

$0

$2,000

$4,000

$6,000

$8,000

$10,000

$12,000

$14,000

1999 2000 2001 2002 2003 2004 2005

$/km

Urban

Short rural

Long rural


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7.3.7 Expenditure on urban feeders is expected to increase in 2000, prior to thecommencement of the regulatory period in 2001, and should continue to increase until2002.

7.3.8 Expenditure per km on urban feeders is several times that on rural feeders. This is to beexpected, given that urban feeders have shorter spans, more distribution substations andgenerally also have higher rates of load growth.

7.3.9 However, on a per customer basis, expenditure is increasing on long rural feeders and is2-3 times the expenditure per customer for urban and short rural feeders.

Figure 7.3.2 Overall Expenditure/Customer by Feeder Type

$0

$50

$100

$150

$200

$250

1999 2000 2001 2002 2003 2004 2005

$/C

ust

om

er

Urban

Short rural

Long rural


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8 DESIGN AND CONSTRUCTION

KEY POINTS

Design and Construction practices are sound. The design and construction of thenetwork is based on sound and well-proven engineering principles.

Section 8.5

Feeder Planning could be improved. For future feeder planning requirements, no one-process owner “owns” the feeder and capacity requirements rather than reliability are thedriver for enhancements.

Section 8.4

Pole top designs have varied. There is a variety of pole top designs in use. The newpole top design should improve reliability but post insulators should be used instead ofpin insulators.

Section 8.6

Transformer pole design is complex. Transformer poles are comparatively clutteredwith phase to phase and phase to earth clearances much smaller than normal lineclearance.

Section 8.6

Feeder protection design has inadequacies. Powercor needs to review feeder fuse,and associated fault ratings to ensure that appropriate protection operation and optimumreliability is being achieved.

Section 8.6

Remote control capability of zone substations is limited. At the end of 1999, only40% of Powercor zone substations had remote control of feeders, inhibiting feederreliability.

Section 8.6

There is no integrated reliability plan. Powercor have developed a number ofinitiatives for improving reliability but there is no integrated plan covering both NetworkPlanning and Network Performance processes to ensure that the optimum solutions arebeing obtained.

Section 8.7

8.1 NETWORK CONFIGURATION

8.1.1 In Victoria, a 22 kV distribution voltage is used in rural and newer urban areas, as distinctfrom South Australia and much of New South Wales, where 11 kV distribution is usedalmost exclusively. There are many advantages in 22 kV distribution networks – lossesare much lower, conductor sizes are smaller and the overlaid subtransmission injectionrequirements are less.

8.1.2 22 kV distribution has some disadvantages. Feeders are much longer. In the case ofPowercor some distribution feeders have a total line length of 1,500 km. Feeder sectionsare longer than normally used at 11 kV because costs and discrimination difficulties limitthe number of in-line section breakers. As a consequence, feeder fault patrols takelonger.

8.1.3 Anecdotal evidence suggests that 22 kV open wire overhead lines are significantly morefault prone than equivalent 11 kV lines. The higher voltage means that the line will arc toearth more readily, making the supply more vulnerable to faults caused by pollution,possums, birds, bark, trees and the like.


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8.1.4 Reliability is affected by the use of automation and remote control which reduces faultresponse times by enabling much of the necessary switching to be undertaken remotely.

8.1.5 Powercor is installing remote control to selected reclosers and switches locatedthroughout the network. The switches selected are chosen to improve response timeson feeders where location is difficult or which are known to be particularly prone to faults.

8.2 CAPITAL EXPENDITURE

8.2.1 In their 2001 pricing submission to the Office, Powercor also provided capital expenditurefor 1999 and 2000 for a range of asset groups such as urban, short rural, long rural etctogether with projected costs for 2001 to 2005. The urban, short rural and long ruralinformation incorporates costs for both HV and LV lines and is shown in Table 8.2.1.

Table 8.2.1 Pricing Submission Capital Expenditure ($ 000's)

AssetGroup

1999 2000 2001 2002 2003 2004 2005

Urban 6,660 8,225 9,492 11,095 10,103 10,620 10,075

Short rural 8,186 10,744 10,270 12,891 12,007 13,602 14,018

Long rural 14,855 19,850 20,329 24,155 21,985 26,762 24,616

Sub transm. 2,550 9,629 18,841 14,329 14,690 24,160 14,975

Metering 10,244 11,669 13,816 13,556 13,582 13,909 14,148

Street lights 2,423 2,504 2,455 2,399 2,410 2,487 2,528

Total 44,918 62,621 75,203 78,425 74,777 91,540 80,360

8.2.2 For each feeder types the CAPEX expenditure can be further broken down (Table 8.2.2)into reinforcements, reliability/quality maintained and reliability/quality improved.

Table 8.2.2 Pricing Submission CAPEX for Rural and Urban Feeders ($ 000's)

Asset Group 1999 2000 2001 2002 2003 2004 2005

Reinforcements

Urban 608 1,750 2,864 2,193 1,919 1,929 1,608

Short rural 955 2,883 2,112 2,612 2,393 2,929 3,361

Long rural 2,778 6,854 7,223 8,258 6,552 7,146 6,320

Reliability and Quality maintained

Urban 5,136 5,363 5,174 7,549 6,831 7,338 7,114

Short rural 5,774 6,091 5,844 8,126 7,461 8,520 8,504

Long rural 10,287 10,822 10,264 13,252 12,788 16971 15,651

Reliability and Quality improved26

Urban 916 1,112 1,454 1,353 1,353 1,353 1,353

Short rural 1,457 1,770 2,314 2,153 2,153 2,153 2,153

Long rural 1,790 2,174 2,842 2,645 2,645 2,645 2,645

26 In subsequent correspondence (Document P146), Powercor have adjusted the proposed expenditure

allocation between urban, short and long rural for reliability expenditure improvement CAPEX, although thetotal expenditure per year would remain the same. This is discussed in section10.


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8.2.3 The expenditure on reliability and quality improvements is considered in Section 10. Theexpenditure on enhancing the network due to load growth and customer requirements,and the expenditure on customer connections has been excluded altogether from thetables presented above as this is also considered outside the scope of this investigation.

8.3 NETWORK PLANNING

8.3.1 Area planners produce annual plans for each zone substation considering load growthover the following ten years. Customer perspectives may bring forward developmentwork earlier than planning studies would indicate.

8.3.2 The criteria for augmentation stated in Powercor policy27 is for it to be initiated when theforecast load exceeds the thermal rating of the equipment. Timing is determined bythermal rating; load growth; protection coverage limitations; protection and other systemplant ratings; voltage regulation; level of load at risk and prospective loads increases.

8.4 FEEDER PLANNING

8.4.1 In relation to feeders (distribution assets), Powercor planning policy overview28 is

The primary aim of distribution planning is to effectively plan the development of thedistribution system to meet existing and future load requirements of PowercorNetwork whilst maintaining a reliability of supply that meets the expectations ofPowercor and minimises inconvenience to customers

8.4.2 The planning responsibilities include: -

• Load forecasting

• Evaluating the capability of the existing system

• Identifying deficiencies in the system and formulating schemes to overcome these

• Selecting schemes on the basis of technical, economic and environmental analysis

• Initiating action plans to implement the preferred scheme

8.4.3 The Network Planning section in Market Street focuses on the subtransmission systemwith Area Planners located at Sunshine, Geelong, Bendigo and Ballart concerned withthe feeder backbone. The spurs, including SWER, are the responsibility of NetworkPerformance. Network Planning and Network Performance are separate processstreams, reporting independently to the General Manager - Network. Powercorrecognises that the level of interaction between these streams may need to increase.

8.4.4 The available planning reports for the zone substations relating to the feeders beinginvestigated were reviewed by PB Power. These planning studies only considered thecapacity requirements of the feeder backbone (would the feeder satisfy future loadgrowth requirements) and were the protection settings appropriate. The reports did notconsider the feeder reliability when developing future plans.

8.4.5 No one process owner “owns” the feeder from a future planning perspective. This couldlead to sub optimal solutions from a customer perspective.

8.4.6 Subtransmission plans reviewed consider reliability factors but feeder studies make nomention of reliability requirements.

8.4.7 Demand side management will defer the need for feeder capacity enhancement but willresult in a marginal improvement to feeder reliability.

27 Document P70 Network Planning Policy Guidelines version 1 Date 20th May 199928 Document P70 Network Planning Policy Guidelines version 1 Date 20th May 1999


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8.5 DESIGN AND CONSTRUCTION

8.5.1 Distribution line design is generally in accordance with SECV standards. Thesestandards have changed over the years as new improved products have becomeavailable and older designs have proven inadequate. A rough guide to the amount ofmaintenance undertaken in older areas is the extent to which feeders have beenrefurbished to meet more modern design standards. Benign environmental conditions insome areas are such that refurbishment to more modern design standards is neithernecessary nor cost effective.

8.5.2 The overall design and construction of the network has adopted sound and well-provenengineering principles.

8.6 FEEDER COMPONENT ITEMS

8.6.1 Figures 8.6.1 to 8.6.7 are a series of photographs showing various feeder components.

Poles

8.6.2 Both wooden and concrete poles have been used. Hardwood poles were initially usedbut more recently concrete poles have become standard. Powercor has recently movedback to using treated wooden poles (approximately $300 per pole) and new concretepoles (approximately $900 per pole) are to be no longer installed. From a reliabilityperspective, both wooden and concrete poles give good service. However, concretepoles are effectively earthed by the steel reinforcing providing a current path to earth.This influences pole top design.

Crossarms

8.6.3 SECV standards over the years have favoured both wooden and steel crossarms (seeFigures 8.6.1 and 8.6.2). Both have limitations under certain conditions. Steelcrossarms can corrode quickly in exposed coastal environments. The use of boxed steelcrossarms exacerbates the problem since internal corrosion cannot easily be detecteduntil it has reached an advanced stage. When combined with concrete poles, theyprovide a current path between the base of the insulator and earth, exacerbating birdproblems as a bird standing on the crossarm and contacting a live conductor can causea phase to earth fault. The current Powercor standard is to use a steel crossarm and awooden pole so this is less of an issue.

8.6.4 Wooden crossarms tend to shrink when the wood dries. This loosens the bolt attachingthe insulator to the crossarm, allowing leakage currents to form arcs across the small airgaps so created. These arcs can cause local heating and eventually a pole top fire.

8.6.5 In some areas, particularly in coastal areas around Terang, wooden crossarms are proneto infestation by a fruit fungus. This is a particularly nasty infestation as the fungus caneat away the inside of the crossarm removing all its strength, with no damage visiblefrom the ground. Infestation by this fruit fungus is classified a Priority 1 defect and, whendetected, crossarms so infected are replaced within 24 hours.


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Figure 8.6.1 Lightning Arrestor Correctly Installed on a Transformer

Figure 8.6.2 Bird Covers Fitted to a Steel Crossarm


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Figure 8.6.3 SWER ACR Fitted to a Tee-Off SWER Line

Figure 8.6.4 Expulsion Drop Out Fuse on a Tee-off Connection


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Figure 8.6.5 Old Style and Modern Cruciform Construction

Figure 8.6.6 Excessive Equipment Attached to Recloser


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Figure 8.6.7 Details of Excessive Equipment attached to a Recloser

Insulators

8.6.6 The original lines built by SECV used 22 kV pin insulators. However there are twoproblems with this type of insulator.

• The upper shed is larger than the one below it forming an “umbrella”. This protectsthe lower shed and the underside of the upper skirt and prevents rain washing offpollutants, in time reducing the effectiveness of the insulator creepage path.

• The insulator porcelain is screwed onto the steel pin. Corrosion of the pin within theinsulator body can cause it to expand and eventually crack the insulator. Onceconductive moisture enters this crack, the insulator will fail.

8.6.7 Powercor have moved to “self cleaning” line-post insulators that overcome most of theabove problems. They had previously used four shed 22 kV insulators but these werefound to be inadequate for parts of the Victorian environment. Twelve shed insulatorswere subsequently used to provide increased creepage and reduce the bird and possumproblems.

Pole Top Design

8.6.8 Because of the changes in standards over the years, there is now a variety of pole toparrangements in use. Some of these combinations have proven to have particularreliability problems.

8.6.9 Pin insulators mounted on wooden crossarms in polluted or corrosive environments are arecognised pole fire hazard. As described above, these insulators are prone both tocracking and to pollution deposit, both of which reduce the insulator’s effectiveness.Consequently, tracking between phases can occur, causing arcing between looseinsulator pins and wooden crossarms. Such arcs can and do cause pole fires.


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8.6.10 While maintenance practices such as tightening all pole top hardware, insulator washing,and the application of grease can alleviate the pole top fire problem, these are short-termmeasures with limited effectiveness. Another possible solution is to bond together thebase of all pin insulators. While this is likely to be effective in stopping pole top fires, itmay increase the number of outages due to lightning and switching transient conditions,as the structure would have a lower basic impulse level. This should not be significantwith wooden poles as the length of wood removed by bonding across the crossarm isrelatively short compared to the wood insulation provided by the pole. However, it maybe a problem with concrete poles.

8.6.11 The favoured permanent solution has been to replace such structures with steelcrossarms and 12 shed self-cleaning post insulators in a cruciform configuration.Powercor have recently made a change to their standard 22 kV pole top configuration toan arrangement using self-cleaning pin insulators and steel crossarms.

8.6.12 PB Power has assessed this new arrangement and believes it has the potential tosignificantly improve reliability. It should be noted though, that the reintroduction of pininsulators brings back the pin corrosion and cracking problem. Suppliers haveapparently indicated that the cost of the pin insulator and the self-cleaning 12 shed line-post are the same. On this basis the use of the 12 shed line-post insulator should bereconsidered. Pin insulators are also prone to pinhole punctures are very difficult todetect whilst line-posts are not subject to this type of failure.

8.6.13 The new design shows the bracket supporting the centre phase insulator bonded to thesteel crossarm. This bonding is not indicated on all drawings and the possibility remainsthat erection crews could omit it. In such an event, a potential for setting fire to the top ofthe pole will remain.

8.6.14 Birds, particularly crows, are a problem in some areas. As indicated above, structureswith concrete poles, steel crossarms and short insulators are particularly vulnerable asbirds can bridge the insulator, causing phase to earth contact. One solution commonlyused by Powercor is to fit a PVC bird (see Figure 8.6.2) cover to the top of the crossarm.Another solution is to fit a large PVC disc to the base of the insulator. The latter option isnow preferred as insects tend to nest between the crossarm and the top shroudattracting birds and still causing flashovers. The PVC disc is a good solution but UVdegradation may become an issue.

Distribution Transformers

8.6.15 Pole mounted distribution substations are a particular problem and prone to faults frombirds, possums and lightning. Transformer poles are comparatively cluttered (seeFigures 8.6.6 and 8.6.7) with phase to phase and phase to earth clearances muchsmaller than normal line clearances. The same can also be true for poles supporting gasswitches and overhead line fuses.

8.6.16 Mitigation measures taken by Powercor include:

• All high voltage leads on such poles are now made from insulated conductor so thatbirds and animals contacting two conductors simultaneously will not cause a fault. Inaddition, shrouds are used on exposed bushing terminations.

• Aluminium possum guards are fitted as standard on all wooden transformer poles.This only has limited effectiveness, particularly on structures with insulated lowvoltage overhead conductors as possums can reach the transformer by crawlingalong the conductors. Trees in close proximity to lines and structures also providethe opportunity for possums to by-pass the possum guard. However the use of theseguards can be effective and their greater utilisation would reduce if not eliminate thenumber of outages due to animals.


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• Surge arrestors are fitted to all transformers rated at 50 kVA and above and alltransformers at the end of a line. Surge arrestors are designed to provide a path forsurge currents to flow to ground to prevent high surge voltages damaging transformerwindings, cables and other sensitive electrical equipment.

8.6.17 If surge arrestors are to provide maximum effectiveness, care must be taken with theway they are mounted. Connection leads have high surge impedance and,consequently, if arrestors are not fitted correctly, even arrestors that operate as designedcan place very high surge voltages on the equipment they are supposed to protect. Newtransformers now have arrestor-mounting brackets affixed to the transformer tank toallow arrestors to be mounted as close as possible to the transformer bushing. Thereare many arrestors on the network that are not mounted in this way and which thereforemay not be as effective as intended. This maybe a contributing factor to the highincidence in the Powercor network of outages caused by lightning.

8.6.18 It is also important for the fuses protecting the transformer to be properly rated to avoidfuse operation because of surge follow currents correctly passed by the arrestor. Fuseratings below 10 amps have been found to mal-operate under these circumstances butmay be necessary where system fault levels are low.

8.6.19 As surge arrestors are relatively expensive, Powercor policy, based on an economicassessment, is not to use them on small transformers except where the transformers arelocated at the end of a line where the risk of lightning damage is thought to be higher.Small transformer failures, because of “lightning damage”, however do cause manysystem faults.

Protection

8.6.20 Many faults are categorised as mal-operation where fuses are judged to have operatedincorrectly. Furthermore, in lightning storms many interruptions are caused by fuseoperation. It may be that the fuse ratings currently used are too low. Overseasexperience indicates that, in many cases, higher fuse ratings would eliminate spuriousfuse operations without exposing equipment to unacceptable risk of damage. It isunderstood that 3 amp fuses were originally used to protect small transformers but thisrating has now been increased to 5 amp.

8.6.21 Fuses are used to protect against overload and short circuits. While transformers arerugged devices, and can withstand overload currents for a short time, even a 3-amp fuseis of limited value in protecting small transformers against overload. The full load currentof a small 20-kVA single-phase transformer is less than one amp.

8.6.22 Thus, the main function of high voltage transformer protection is not to protect againstoverload but to ensure that defective equipment is isolated from the system and thatdamage is limited when a fault occurs. A secondary purpose is to provide a convenientmeans of isolating the transformer from its high voltage supply for maintenance reasons.

8.6.23 If the purpose of a fuse is for fault rather than overload protection, then its rating is not socritical provided that, the system fault level at the point of installation is sufficient for thefuse to operate under genuine equipment fault conditions. The rating chosen also needsto allow for coordination/discrimination with upstream protective devices.

8.6.24 Higher fuse ratings may prevent unnecessary fuse operations and result in a morereliable supply. It has, however, been suggested that on long rural feeders, that faultratings at the end of the feeder may be too low to ensure effective high rated fuseoperation under fault conditions. Powercor needs to review fuse and associated faultratings to ensure appropriate protection operation and that optimum reliability is beingachieved.

8.6.25 The length of some of the long rural 22 kV feeders could dictate transformer fuse sizes.Such feeders may have four or five protection devices in series between a transformer atthe end of the feeder and the feeder circuit breaker at the zone substation. In suchcircumstances, it is difficult to get the protection to discriminate properly unless operating


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currents of protective devices are progressively reduced as distance from the zonesubstation increases. Protection coordination problems experienced on the BAN008feeder may, in part, be caused by the fuse ratings used to protect the larger capacitytransformers in Daylesford town.

8.6.26 Powercor have advised that they recognise that mal-operation of feeder protection is aproblem and that the issue is being investigated.

Control devices

8.6.27 At the end of 1999, only 40% of Powercor zone substation had remote control. In anumber of cases, the system control and data acquisition (SCADA) is rudimentary. Theproposed SCADA replacement and extension of this capability will help to improvereliability. According to information supplied by Powercor29, in some location it will not beafter 2003 that full control is available (Camperdown, Corio, Hamilton, Horsham, Terang,Warmambool and Winchester). Powercor also have a comprehensive GIS system thatassists in customer fault management. Powercor are planning further technology in theform of a mobile data terminal although the full benefits of existing technology are yet tobe realised.

8.6.28 Powercor have remote control of a number of sectionalising switches on feeders. Insome locations cases due the variable coverage of the trunk mobile radio network,remote control of these switches can not guaranteed at all times.

8.7 CONCLUSIONS

8.7.1 Planning at a subtransmission level is considered appropriate although subtransmissionplanning has been not considered in detail as part of this investigation. Future planningat a feeder level requires better integration with reliability requirements. In some cases,Powercor is advancing future requirements for capacity because of reliabilityrequirements, which is to be commended.

8.7.2 Powercor have developed a number of initiatives for improving reliability but there is nointegrated plan covering both Network Planning and Network Performance processes toensure that the optimal solutions are being obtained. The groups meet on a monthlybasis to discuss developments but the use of an Asset Management Plan would ensuremore effective coordination and communication.

29 Document P102 Status of SCADA in Powercor


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9 OPERATION AND MAINTENANCE PRACTICES

KEY POINTS

Many of Powercor documents cited were in draft form. Key documents are in draftform such as procedure for identifying defects and repair requirements, Asset InspectionWork Practice and on-line process information.

Section 9.1

Powercor has a high re-inspection rate of contract maintenance inspectors.Powercor use an independent contractor for maintenance inspection of feeders but thenuse their own staff to re-inspect 10% of the work, leading to some being visited up tothree times.

Section 9.3

Management of customers during faults could be improved. Powercor receiveabout 1 million calls per year (fault and non-fault) which appears to be high. Customersreporting a fault are required to listen to two messages before speaking to an operator.

Section 9.6

Fault restoration process could be improved. Restoration following faults may bebeing delayed by operators choosing to patrol a feeder following a fault instead of tryinga reclose. Pre-prepared restoration plans would assist in outage co-ordination.

Section 9.6

Vegetation management could be improved. Outages due to vegetation are notreducing. The inability to get vegetation trimmed in a timely manner by local Shires innon-bush fire areas is likely to be impacting on supply reliability.

Section 9.7

9.1 ASSET MAINTENANCE

9.1.1 Asset inspection criteria and associated maintenance standards (frequency, conditionassessment and remedial measurers required) are important to ensure that assets areappropriately maintained. Maintenance is intended to ensure that the assets retain theirexisting capability whereas development enhances capabilities.

9.1.2 Asset condition deteriorates over the life of an asset. Various factors influence the rateof such deterioration including the environment, maintenance history, original quality ofdesign and construction and the operating regime of the asset. Inspection regimes needto take into account the environment, duty to which the asset has been subject to over itslifetime (number of operations) and the reliability with which the asset is expected toperform.

9.1.3 Maintenance policies can be established so that depending on the condition of the asseton inspection, different maintenance is carried out. This approach is classed ascondition based maintenance. Powercor have adopted a condition based maintenanceapproach. However, they are presently reviewing this approach by considering differentinspection and maintenance practices for the same asset type in differing environments.For example, Powercor are reviewing their maintenance of the same assets types whenthey are located in coastal and non coastal areas as they consider that differingmaintenance practices are required for the same asset type located in these differingenvironments.

9.1.4 Many companies are introducing reliability centred maintenance (RCM) into their assetmanagement practices. This overlays the time based inspections. The approachconsists of centering maintenance on the reliability being achieved, from the asset. Thisapproach leads to maintenance being carried out depending on condition, location and


Doc No.71321 19/09/00 Page 80

performance characteristics being achieved as well as the impact of equipment failure.The inspection regime is adjusted to satisfy the various reliability centred maintenancerequirements. The maintenance of assets is carried out by an inspection regimeaccording specific maintenance standards. Depending on the condition of the equipmentfound during inspection, various maintenance works are carried out.

9.1.5 Varying the frequency of inspection, the maintenance inspection criteria and what isinspected can modify the inspection regime.

9.1.6 Powercor assign a number of categories to maintenance requirements identified throughthe inspection program. These requirements can be urgent in nature or need to becarried out within specified times. The inspection information is up loaded into SAP fromhand held data recorders that are used in the field to record the inspection results.

9.1.7 The categories assigned to maintenance are: -

• P1 - work must be done immediately

• P2 - work must be done within 14 weeks

• Programmed maintenance – work must be done within 2 years

9.1.8 P2 jobs identified by the inspection process are down loaded from SAP for analysis inExcel and notifications are then prepared by the Priority Maintenance Officer. A designreview is carried on by Powercor Services on behalf of Networks, followed by the issuingof a Work Instruction to Powercor Services for them to carry out the work. The PriorityMaintenance Officer also arranges material requirements

9.1.9 Programmed maintenance jobs identified by the inspection process are also downloaded from SAP into Excel by the Programme Maintenance Officer, who then decideswhat action should be taken. The work is also subject to a design review.

9.1.10 Powercor’s procedure for identifying defects and repair requirements30 appears to still bein early draft form, with no process owner identified and many gaps in the document stillto be completed. Whilst it is appreciated that Powercor is heavily reliant upon its intranetsystems for storing and distributing such procedures, many of the staff likely to use thisprocedure do not have ready access to a computer at their place of work. Otherexamples of important documents being incomplete are the Asset Inspection WorkPractice31 and a computer screen listing32 which shows Priority 1 and 2 MaintenanceProcedures, Asset inspection, conductor clearance, working near power lines andseveral other important procedures being still listed in draft form. Without suchprocedures completed and disseminated to the appropriate Powercor staff andcontractors they are reliant upon work practice procedures that pre-date the introductionof SAP and the Business Management Framework (BMF).

9.1.11 Figure 9.1.1 shows the High Level Process Flow for Identifying and Repairing Defects.

9.1.12 This process diagram reflects the operation of the business as perceived duringinterviews and visits to sites. Aside from a potential conflict on resources with both theretail customer call centre (trouble orders and priority 1 defects) and the worksmanagement (planned work) directing work to the service provider the system appears tobe well structured and to operate effectively.

30 Document P43 - Identify and Repair Defect Procedure, undated31 Documents P45 and P49Asset Inspection Work Practices draft 1 17 march 199932 Document P118 - Screen listing of Draft Business Management Framework Procedures


Doc No.71321 19/09/00 Page 81

Complete work asrequested.Update systems.

Return completed file toWorks Management.

Advise Outage co-ordinatorof details if the defect wasissued on a trouble order.

Inspect Assets.Identify Defects and classifyas Priority 1,2 or non-priorityin the PDE. Report Priority 1

items to the call centreimmediately.

(Ser

vice

Pro

vid

ers)

Res

ou

rce

Pla

nn

ing

Des

ign

Co

nst

ruct

ion

Ass

et In

spec

tio

n

(Net

wo

rk)

Wo

rks

Man

agem

ent

(Net

wo

rk)

Mai

nte

nan

ceA

sset

Per

form

ance

(Ret

ail)

Cu

sto

mer

Cal

l Cen

tre

Identifyand Issue

AssetInspect

Receive advice ofdefect from

Customer, or of apriority 1 defectfrom the Asset

Inspector. Raise

Upload PDE. Identify workto be completed. Raiseprojects. Issue to Works

Management.

Resource Project. Issue toService Provider.

Ensure paperwork issigned off. Update

Project status is the SAP

Audit file to ensure scopewas achieved, and that

systems have beenupdated correctly. Arrangefor field audit if required.

Complete troubleorder. Tick for

follow up if advisedto do so.


Doc No.71321 19/09/00 Page 82

9.1.13 Powercor are also in the process of developing a model to forecast priority maintenancework loads. Its main benefit will be more effective resource scheduling. Powercor intendto validate the model against actual priority maintenance. There are also plans to build amodel for programmed maintenance work.

9.1.14 Powercor advised that all defects are attended to and that there is minimal maintenancebacklog33.

9.2 MAINTENANCE EXPENDITURE

9.2.1 Powercor expense some maintenance activities and capitalise others. The followingsections review the expenditure under these two categories.

Maintenance operating expenditure

9.2.2 In their 2001 pricing submission to the Office, Powercor provided maintenanceexpenditure for 1999 and 2000 under for range of asset groups such as urban, shortrural, long rural etc., together with projected expenditure for 2001 to 2005. The urban,short rural and long rural information incorporates expenditure for both HV and LV lines.This maintenance expenditure is that which is expensed and is shown in Table 9.2.1.

9.2.3 The accounting treatment of maintenance expenditure can vary from company tocompany depending on accounting practices. Often if just one component is beingreplaced, the activity is expensed, whereas if a number of components are replaced, thework is classed as capital. For example, if one pole were being replaced, this would betreated as maintenance whereas if a number of poles in a line were being replaced aspart of a refurbishment program, then this would be treated as capital. Powercor’spractice is to treat all these activities as capital.

Table 9.2.1 Pricing Submission Maintenance Expenditure ($ 000's)

Asset Group 1999 2000 2001 2002 2003 2004 2005

Urban 5,157 5,956 6,436 6,492 6,506 6,395 6,370

Short rural 5,026 5,677 6,315 6,384 6,396 6,272 6,264

Long rural 11,116 12,304 14,206 14,414 14,445 14,313 14,370

Subtransmission 2,398 2.731 3,003 2,866 3,013 2,965 2,840

Metering 1,300 900 1,300 1,300 1,300 1,300 1,300

Street lighting 1,300 2,100 2,057 2,090 2,121 2,151 2,181

Total 26,297 29,668 33,317 33,546 33,781 33,396 33,325

9.2.4 Powercor’s financial system does not record costs under the categories shown in Table9.2.1, which were used by the Office in templates developed for DBs’ pricing reviewsubmissions. Powercor has estimated these costs based on a range of functiongroupings that they use for recording costs. The function grouping presently used forrecording operational maintenance34 costs along with costs for 1997, 1998 and 1999 forfeeders is shown in Table 9.2.2 with some function groups combined.

33 Documents P115 Asset Inspection performance v program 1999 and P116 Status of Outstanding 1998

CAPEX and OPEX maintenance Work34 Document P61 Feeder operational expenditure 1997/98/99


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Table 9.2.2 Operational Maintenance Costs provided by Powercor ($ 000's)

Functional Group 1999 1998 1997

Faults 8,871 8,040 8,658

Zone substation maintenance 1,296 1,700 1,962

Operations 2,625 1,700 1,962

Overhead line maintenance and conductor clearance 3,406 3,050 4,198

TV interference investigation 1,497 1,752 0

HV installation maintenance 873 919 1,562

Line inspection 1,670 1,419 2,835

Vegetation 10,644 15,435 16,864

Meter and time switch maintenance 1,622 1,058 1,102

Public lighting maintenance 1,660 295 2,673

Supply negotiation 1,355 355 727

Total 35,519 36,677 39,581

9.2.5 It is noted that there are discrepancies between Table 9.2.1 Pricing SubmissionMaintenance Expenditure ($ 000's) and Table 9.2.2 Operational Maintenance Costsprovided by Powercor ($ 000's) such as the total for 1999 in the Office price submissionis different from the total based on functional costs. The reasons for the differences arelikely to be due to costs being included Powercor in Table 9.2.2, that have been includedin other operational costs such as faults in the Powercor pricing submission.

9.2.6 Some of the key changes in actual costs over the last 3 years have been: -

• Maintenance expense costs have reduced by $4m from 1997 to 1999.

• Savings have been achieved in vegetation management. Powercor advises that this$6.2m saving is due to contracting out with resources better-focused andconsequential cost efficiency. Powercor also stated that the number of faults due totrees is similar to the number before the work was contracted out

• Zone substation maintenance costs reduced by $0.7m

• Operations costs increased by $2.6m

• Overhead line maintenance costs reduced by $0.6m. It should be noted that allmaintenance replacement work is treated as capital and hence is not included in theabove table

• TVI (television interference investigation) costs increased by $1.5m. This may be dueto a category reclassification, with costs having been recorded elsewhere previously

• Line inspection costs reduced by $0.8m due to the reduction in frequency

9.2.7 Powercor do not record operational maintenance costs at an individual feeder level sodirect operational maintenance expense cost comparisons between feeders is notpossible. Comparisons of operational expenditure between feeder types are onlypossible based on the estimated allocations for urban, short rural and long rural. Table9.2.3 Pricing Submission Maintenance Costs per km ($'s) and Table 9.2.4 PricingSubmission Maintenance Costs per Customer ($'s) show these comparisons for urban,short rural and long rural feeders. The maintenance costs are for both HV and LV butexclude subtransmission. The feeder lengths are HV distribution line lengths.

9.2.8 The expenditure per km for urban feeders is about 13 times that for long rural feedersand about 5 times that for short rural feeders. From a customer perspective, long ruralfeeder customers typically have 2.5 times the expenditure per customer than for urban orshort rural feeders.


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Table 9.2.3 Pricing Submission Maintenance Costs per km ($'s)

1999 2000 2001 2002 2003 2004 2005

Urban 3,429 3,961 4,280 4,317 4,327 4,253 4,236

Short rural 665 751 835 844 846 830 829

Long rural 256 283 327 332 332 329 331

Table 9.2.4 Pricing Submission Maintenance Costs per Customer ($'s)

1999 2000 2001 2002 2003 2004 2005

Urban 28 33 35 35 36 35 35

Short rural 25 28 31 32 32 31 31

Long rural 62 68 79 80 80 79 80

9.2.9 HV and LV maintenance expensed costs are shown in Table 9.2.5 HV and LVMaintenance Expensed Costs ($'s).

Table 9.2.5 HV and LV Maintenance Expensed Costs ($'s)

Maintenance Costs/km Maintenance Costs/customer

HV HV and LV HV HV and LV

Urban 1,525 3,429 13 28

Short rural 342 665 13 25

Long rural 223 256 53 62

9.2.10 When only HV maintenance operational expensed costs are considered, the expenditureon urban feeders is seven times that for long rural feeders on a per km basis. Thiscompares with 12 times when HV and LV costs are considered. On a per customerbasis, the ratios are four times for HV costs only and 2.5 times for HV plus LV costs.Specific reasons for the differences in expenditure on urban feeders compared with longrural feeders have not been determined.

9.2.11 Reasons for the differences could be due to the Distribution Code requiring urbanfeeders to have a better SAIDI than rural feeders. Conversely, urban networks are olderthan rural networks so greater expenditure could be expected but this is more likely to beconsidered as asset replacement work and classified as maintenance capital (notmaintenance operational). Vegetation costs would also be expected to be higher in ruralareas as Councils carry out the vegetation work in urban areas. The greaterrequirements for fire mitigation would also lead to greater vegetation costs in rural areas.

9.2.12 Maintenance expenditure treated as capital

9.2.13 Powercor capitalise assets replaced as part of maintenance work. This expenditurecovers activities35 (with expenditure in 1999 shown in brackets) such as: -

• Public lighting replacement ($0.5m)

• Fault replacement ($5.6m)

• Transformer replacement ($1.0m)

• HV switch replacement ($0.4m)

• HV fuse and surge diverter replacement ($0.9m)

• Pole life extension treatment ($1.7m)

35 Document P117 Capex by feeder


Doc No.71321 19/09/00 Page 85

• Pole life extension replacement ($1.3m)

• Pole life extension staking ($0.3m)

• Overhead and underground line replacement ($1.0m)

• Replacement of meters and time switches ($3.2m)

• Cross arm replacement ($5.2m)

• Bushfire mitigation ($0.4m)

• Conductor clearance program ($3.9m)

9.2.14 Several of the above items would appear to be of a routine maintenance nature (eg. fusereplacement, fault repairs, bushfire mitigation) and but are treated as capital byPowercor.

9.2.15 Future expenditure for urban, short rural and long rural is shown in Table 9.2.6 PricingSubmission Maintenance Replacement CAPEX Costs per km ($'s) and Table 9.2.7Pricing Submission Maintenance Replacement CAPEX Costs per Customer ($'s)

Table 9.2.6 Pricing Submission Maintenance Replacement CAPEX Costs per km($'s)

1999 2000 2001 2002 2003 2004 2005

Urban 3,415 3,566 3,441 5,020 4,543 4,880 4,731

Short rural 764 805 773 987 987 1,127 1,124

Long rural 237 249 236 304 294 390 360

Table 9.2.7 Pricing Submission Maintenance Replacement CAPEX Costs perCustomer ($'s)

1999 2000 2001 2002 2003 2004 2005

Urban 28 29 28 41 37 40 39

Short rural 28 30 29 40 37 42 42

Long rural 57 60 57 73 71 94 87

9.2.16 Expenditure per km is still very for urban feeders with expenditure per customer higherfor long rural customers.

9.3 INSPECTIONS

9.3.1 Powercor use an independent contractor to carry out their feeder inspections. Powercorconsiders the results of these inspections. Prior to carrying out maintenance workPowercor re-inspect 10% of the inspections. The initial inspection is ground based usingpowerful stabilised binoculars whereas the additional inspection is by climbing poles anddrilling where necessary. The re-inspection enables Powercor to audit contractorperformance and climb poles identified by inspectors as requiring more detailedinvestigation.

9.3.2 This process enables Powercor to control the actual maintenance work carried out butnot necessarily as economical as some poles could be visited up to three times in orderto inspect and carry the required maintenance work.

9.3.3 In addition, of note is that poles that fail following an inspection are only a small fractionof the poles inspected.


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9.4 WORK MANAGEMENT

9.4.1 Works Management coordinates work for Network Group prior to requesting PowercorServices to carry out the work. Resource scheduling is carried out by PowercorServices. This year there has been a 300% increase in work from last year. Three newzone substations have been constructed. Network Development section within Networksis also moving to managing major projects directly.

9.4.2 In programming work, Powercor classify how each project should be implemented; liveline; in shutdown, state or either will do. Powercor track projects using SAP bymonitoring performance against milestones. Dates are fixed with no float whenestablishing programmes. The aim of work management is to level resources.

9.4.3 Powercor anticipate difficulties in achieving the entire work program due to industryresource constraints. This is accentuated by work other DB are also intending to carryout. 30% of their work is contracted out. Planning horizons for work management is 12months with the aim of moving to 5 years.

9.5 FIELD MANAGEMENT

9.5.1 Powercor has field staff to carry out the physical work on feeders at Balarat, Bendigo,Colac, Geelong, Horsham, Mildura, Shepperton and Warrnambool, Werribee along withlocal service agent’s areas covering areas such as Nhil, Ouyen, Portland etc.36. Thereare also office based field support staff located in Balarat, Bendigo and Sunshine.

9.5.2 The local service agent’s carry out fault-finding and minor maintenance but not majorrepairs of maintenance such as changing cross arms where other than a ladder isrequired to carry out the work. There are presently 12 local service agents who havebeen in place for up to 12 months. They generally work in their own areas but whenproblems escalate, resources are transferred to adjacent areas. They also do projectwork but this is managed separately.

9.5.3 The local service agents are retained under a contract with Powercor and paid a retainerin addition to call out costs. The contract has a range of measures such as customersatisfaction (internal and external) and there is a bonus scheme linked to the measures.Powercor report a level of satisfaction with the service being provided. The local serviceagents are branded as Powercor.

9.5.4 In local areas there have been problems establishing the local service arrangements dueto Enterprise Bargaining Agreement problems and the availability of suitable contractors.Powercor were not able to indicate what their long-term vision for service agents was.

9.6 FAULT MANAGEMENT

9.6.1 Call centre staff in Market Street or at Bendigo handle customer fault calls. Theinformation is then forwarded electronically to outage coordinators at both locations whodispatch the field staff taking into account various priorities. Powercor dispatch about54,000 jobs of which 20,000 to 23,000 relate to outages and receive about 1 million callsper year (fault and non-fault). This number of calls equates to every customer calling twotimes per year, which appears to be high.

9.6.2 Both Market Street and Bendigo can operate independently. Market Street is used afterhours (after 4,20 pm and before 7am) including weekends for all calls. Bendigo andMarket Street receive normal customer calls with Market Street normally handling all faultcalls with overflow to Bendigo.

36 Document P101 Indicative Service Agent Boundaries - drawing issued February 1999


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9.6.3 For each event the new Outage Management System (OMS) can record the start time,assigned time dispatched time, on route time, arrival time, restored time, completion timebut all of these are not presently being recorded. Powercor have had difficulties with theinstallation of the new OMS and have been tracking the number of outstanding eventsnot closed off. The old OAS recorded start time, dispatch time, restored time anddispatcher resolved time.

9.6.4 Their automated voice answering system is initially loaded with a “2-hour restoration timemessage” until further information has been obtained. The message length is limited to34 seconds.

9.6.5 It appears that customers wanting to report a fault have to listen to two messages, whichcould mean they have to wait for just over a minute to report a fault. The automatedvoice message system may be therefore preventing Powercor from getting timelyinformation from customers about fault location which could assist in more accuratelylocating the fault cause and thus increasing outage times. Customers could well be“hanging up” instead of waiting to pass on the information they have about a possiblefault cause.

9.6.6 The fault management system assists Powercor in identifying the extent of the fault.When calls are received, the customers are mapped onto the GIS, which has algorithmsto tell the controller the extent of the feeder affected. There have been occasions wherea customer has rung in and advised of a fault but the algorithm has ignored the callbecause it had already escalated the fault to a feeder fault. When the feeder wasrestored, the system had not recorded that the customer was still off supply andremained so for several more hours until they rang in again. There are is no easysolution to this, to ring every customer affected by a fault to check that their supplied hasbeen restored is the ultimate but impractical solution.

9.6.7 Powercor use a procedure for feeder patrols and supply restoration prepared by a jointworking party of the Office of the Chief Electrical Inspector and agreed upon by allparties37. If the specific cause is known, supply may be restored to the remaining sectionof the line.

9.6.8 Before attempting a manual reclose for unknown causes, the Network Controller isrequired to: -

• Contact appropriate external response centre

• Seek information on equipment, weather

• Consider fire concerns, location, environment

9.6.9 The manual reclose must not occur within 15 minutes of the initial incident unless there isa storm situation or public supplies are affected.

9.6.10 The above procedure places the onus of the Network Controller to decide when it isappropriate to reclose the faulted feeder. This 15 minute mandatory waiting periodresults in outages possibly being extended. The fault statistics indicate that someoperators may not be trying a reclose after the mandatory waiting time, preferring topatrol the feeder before attempting to reclose. In other countries, the waiting period isshorter and unless special circumstances exist or the location of a fault is known, areclose is always attempted before dispatching fault crews.

9.6.11 When a fault incident becomes significant, Powercor have an “availability coordinator”whose function is to take a management role of the incident covering customers,corporate communication liaison, operational coordination etc. This approach isconsidered appropriate.

37 Document P67 Switching: Feeder Patrols and Supply Restoration on High Voltage Overhead Lines No PCA

4115/7.41 issue 1 25 May 1998


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9.6.12 There have been particular instances were the fault duration has been excessive. Forexample, there were significant number of customers affected for feeder BAN008 byoutages on 10/5/99 (5 hours), 16/4/99 (8 hours) and 29/1/99 (8 ½ hours).

9.6.13 In one case, besides there being protracted patrols that took place, restoration wasdelayed due to inadequate procedures being in place for restoration38. The restorationprocess attempted to use a remotely operated switch that was ineffective. Supply wasonly restored when more extensive sectionalising of the feeder was carried out.Powercor’s review of the protection settings confirmed the settings were adequate. Itwas noted that due to the existence of 6.5 km of underground cable, the inrush currentwas causing the protection to operate. The protection review recommended that thecable be disconnected prior to reclosing the switch to avoid the problem in the future.There needs to be well-documented feeder restoration plans available for outagecoordinators, particularly for troublesome feeders as the operator may not be aware ofthis problem and they could repeat the whole saga again.

9.6.14 If Powercor had more appropriate feeder restoration plans in place prior to the incident,the outage may have been much shorter. It is interesting to note that similar problemswere experienced on BAN008 on 1 March 2000, although the problem had beenpreviously highlighted in September 1998. There should have been more than sufficienttime for operational guidelines to have been developed to mitigate future situations. Tobe effective, the guidelines should be feeder specific for known troublesome feeders.

9.7 VEGETATION MANAGEMENT

9.7.1 The Vegetation Management Plan39sets out the processes and responsibilities for ROWmaintenance. The plan is based upon and referenced to the Office of the Chief ElectricalInspectors Code of Practice40. Field observations support that this is an effectiveprocess with only a few instances of trees growing near to power lines.

9.7.2 The specific outage data as supplied from the OAS shown in Table 9.7.1 Total CMOSdue to Trees and Table 9.7.2 CMOS and Incidents as a result of Vegetation41, indicatingthat little if any reduction of outages resulting from vegetation is occurring. By 1999 over240 outages occurred and 4% of all customer minutes lost were due to vegetation, eitheras a planned outage for tree clearing or an unplanned outage as a result of falling treesor bark. As a proportion, this was up from 3% in 1997 although this was due toreductions in other outages.

9.7.3 Expenditure on vegetation management has reduced from $16.9m to $10.6m over thelast three years but the outages due to vegetation are not reducing.

38 Document P56 BAN08 Protection Settings 19 April 200039 Document P44 - Vegetation Management Plan - Code of Practice for Powerline Clearance (Vegetation) July

199840 Document P64 - Code of Practice for Powerline Clearance [Vegetation] 199641 The table includes outages caused by bark although these result in part from adverse weather blowing the

bark onto the overhead lines.


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Table 9.7.1 Total CMOS due to Trees

Total CMOS due to Trees and Tree Clearing

1997 4.3 million minutes



Trend Not improving

Table 9.7.2 CMOS and Incidents as a result of Vegetation

Unplanned tree related incidentsPlannedincidents

Fallen Tree Bark TotalUnplanned

Cut Tree andTreeClearing

Total

% A

ll C

MO

S

Inci

dent

s

% A

ll C

MO

S

Inci

dent

s

% A

ll C

MO

S

Inci

den

ts

% A

ll C

MO

S

Inci

dent

s

% A

ll C

MO

S

Inci

den

ts

1997 1.0% 44 0.7% 43 1.8% 87 1.2% 84 3.0% 171

1998 2.9% 234 0.2% 20 3.1% 254 0.3% 46 3.4% 300

1999 3.2% 180 0.2% 26 3.4% 206 0.4% 41 3.8% 247

Average/ Total

2.4% 458 0.4% 89 2.7% 547 0.7% 171 3.4 718

Trend inrelationto alloutages

Increasing Decreasing Increasing Decreasing Increasing

9.7.4 The Vegetation Management Plan42 sets out the means by which the work is to bemonitored (by using the bushfire mitigation index and customer complaints). It alsostates that the work is audited by the Manager Maintenance Contracts and NetworkServices. It does not refer to the effectiveness of the vegetation management inreducing customer outages. This form of performance incentive maybe covered in thecontract between Powercor and Vemco, which has not been reviewed during thisinvestigation. Such an incentive would seem to be essential given that Powercor spend$10.6m43 per annum on vegetation management and it is a significant controllablecontributor to CMOS.

9.7.5 The Vegetation Management Plan also sets out in some detail the 14-day notificationprocess utilised by the vegetation contractor. This is clearly good practice and shouldfoster good relations with landowners. It is however interesting to note that the PowercorSupplementary Submission to the Office44 sets out a requirement for an additional $1.4per annum to implement a 14 day notification period to property owners and otheraffected persons.

42 Document P44 Vegetation Management Plan Code of Practice for Powerline Clearance (Vegetation ) 199643 Document P61 Feeder operational expenditure 1997/98/9944 Document P95 - Supplementary Submission to the Office of the Regulator General, 2001 Electricity

Distribution Price Review date 20th April 2000


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9.7.6 There are sometimes difficulties in getting trees trimmed. Powercor can declare that theyneed to be trimmed but it is the responsibility in many cases of the local Shires.Powercor may dictate a series of outages for tree trimming to Shires non-bush areas.The inability to get vegetation trimmed in a timely manner will be impacting on supplyreliability in non-bush fire areas.

9.7.7 Bushfire mitigation

9.7.8 The industry developed Bushfire Mitigation Management Framework45 provides a verygood framework for the management of bushfires with clearly defined accountabilities. Arange of inspections, preventative programs and monitoring is specified.

9.7.9 Prior to each fire season commencing, Powercor ensures that appropriate preparationshave been carried out. A Senior Manager completes the Bush Fire Preparednessdocument46 that confirms that Powercor has completed all the pre-declaration mitigationobligations. A statement is also obtained from Vemco (Contractor who carries outPowercor vegetation management) that pre-declaration bushfire mitigation obligationshave been completed. Powercor obligations include ensuring that: -

• The line inspection program is up to date and will remain so during declared period

• All limited life and unserviceable poles are fire safe and will remain fire safe for theduration of the declared period

• All priority maintenance items have been addressed in accordance with currentPowercor policy

• All pre-summer vegetation inspections have been completed and appropriatelydocumented along with vegetation works completed in accordance with Code ofPractice

• All private line inspections are up to date and private lines will remain safe over period

• Maintenance data is up to date in SAP

• A field audit program for line condition is in place

9.7.10 Powercor have strategies to reduce fault impacts during fire season such as reducing thenumber of recloses an auto recloser is permitted. In South Australia, power is often leftoff all day on total fire ban days but this is not normal practice in Victoria, except where aline is known to pose a fire risk. In Victoria, there are also requirements for a completepatrol after a fault during total fire ban periods

9.7.11 On a weekly basis during the bushfire season, a consolidated bushfire mitigation statusreport is completed. This weekly report covers each maintenance planning group areaidentifying the number of fire hazard poles per asset area.

45 Document P21 Bushfire Mitigation Management Framework – no date46 Document P104 Notice of completion of fire mitigation obligations


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10 RELIABILITY IMPROVEMENT INITIATIVES

KEY POINTS

Reliability strategies are not based on sound analysis. Reliability improvementstrategies and plans should be based on analysis of feeder performance with better datacollection and verification processes.

Section 10.1

Model used for reliability analysis is considered rudimentary. The reliability modelconsiders only one years data at a time, but does not consider trends in performance orcarry out a financial ranking of options.

Section 0

Powercor need an integrated strategy for improving reliability. Powercor have anumber of good initiatives for improving reliability (the focus is on the frequency ofoutages and should include means to reduce the duration of outages) but need anintegrated strategy to know best what to do where.

Section 10.4

Effectiveness of inspections. Powercor stated that the inspection of surf coast feederDDL023 (location of recent spate of pole top fires) presently in hand is the first time thefeeder has been checked effectively.

Section 10.4

Supplementary pricing submission reliability initiatives lack rigor. Reliabilityimprovement initiatives in the supplementary pricing submission lack the same degree ofrigor as the original submission.

Section 10.5

Reliability improvement strategies do not appear to be achieving desired goals at afeeder level. Powercor need to take a more structured approach to monitoringperformance and expenditure in order to ensure that performance improvementprograms achieve the maximum cost benefits. Analysis shows a weak correlationbetween expenditure and performance improvement.

Section 10.6

10.1 INTRODUCTION

10.1.1 In determining what are appropriate reliability improvement strategies, a key element isto ensure that decisions are based on sound feeder performance information andanalysis. The structure of the information being collected, along with its accuracy, mustbe such that reasons for a particular feeder’s reliability can be properly understood.

10.1.2 If only the effects of a particular event are recorded, then it will be difficult to decide whatis the appropriate action to be taken to rectify the problem. For example, if the reason fora particular outage was given as “animal” the action required to prevent the faultrecurring is not clear. If the reason for the outage was given as the lack of a possumguard, then management could apply an appropriate strategy to address the problem.

10.1.3 The approach has been taken in the past to target the worst performing (rogue) feederswhere an improvement can readily be achieved. While this approach will hopefullyimprove the reliability, it will not determine the underlying causes. This approach oftenonly looks at the worst performing feeders for the preceding year. Responding to a “oneoff” deterioration in performance will not necessarily result in a long term overallimprovement because the underlying systemic causes will not have been addressed. Ifthe underlying causes of poor performance are well understood, then rectifying thesewould more likely result in consistent and sustained long-term improvement.


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10.2 OAS DATA QUALITY

10.2.1 The validity of basing reliability improvement initiatives on the data that is held in theoutage database is questionable. Powercor Asset Performance staff place a highreliance upon the OAS system (now OMS system) utilised to record all outages. Thesesystems record which and how many customers are affected, the start and end time ofthe outage, the cause (from a predefined list) and the reason (textual description - oftenleft blank) for the outage. The cause and reasons do not enable the root cause to berecorded (eg a cause states “electrical overload” and reason “fuse operation” – neither ofwhich explain why there was an electrical overload in the first place. A fuse operation isnormally expected as the result of an electrical overload).

10.2.2 Reliability improvement initiatives are based largely upon the analysis of this data. Thereare diverse views as to the accuracy of the data recorded within these systems withmanagement believing the data to be 95% accurate47, whilst staff associated with theinvestigation and repair of faults do not have anywhere near this level of confidence inthe data accuracy. Staff responsibilities for the repair of faults have indicated that it isoften not possible to determine the cause of a fault in the field.

10.2.3 Table 10.2.1 below shows that of all the outages in 1997, 26% had no cause found (“NotFound Inspn”) and 24% had nil entry for the outage cause in the outage database. Thevalidity of generating reliability improvement initiatives based on this data with 50% of alloutages not attributed to a cause in 1997 is questionable. Table 9.2.1 also shows thesignificant reduction in Not Found and Nil Entry categories, which reflects a greaterattention to the completeness of the database. The accuracy would be further improvedif some faults were subjected to a post fault inspection.

10.2.4 Other noteworthy changes shown in Table 10.2.1 Causes of Outages in 1997 and 199948

are the increase from 1997 to 1999 of ”birds” being the cause (5% to 18%) and“malfunction” (3% to 19%). It is reasonable to speculate that the population of birds hasnot increased by more than threefold and therefore the number of bird related incidentswould not have gone up in reality by threefold in three years. Similarly it is unlikely thatthe number of outages caused by “malfunction” has increased by 6 times. Table 10.2.2shows a comparative analysis undertaken by Powercor for 1998 and 1999. There is amuch greater level of consistency indicated.

10.2.5 Practical difficulties in locating the cause and the reason (particularly given that manyfaults occur in inclement weather conditions) means that the new data being added tothe database is less than 100% accurate. As demonstrated, data even just 3 yearsprevious to this is highly inaccurate.

10.2.6 There have also been extensive problems with the new OMS system installed inDecember 1999. In Powercor’s Network Performance April 2000 monthly report49, it wasstated that the reliability data is under review with review completion due by 12th April2000 (the data was still not available to PB Power on the 11th May). Lack of this data willbe preventing management from establishing appropriate responses.

10.2.7 Data integrity problems of the nature encountered by Powercor are not unique, validationof this type of data is a problem in other Victorian and overseas distribution companies.

47 Response from Powercor Network Performance Manager to a question, 9th May 200048 Derived from the Outage Availability System data as provided by Powercor49 Document P128 Network Performance Business Report April 2000


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Table 10.2.1 Causes of Outages in 1997 and 1999

CAUSE of OUTAGE 1997 1999

No of outages % No of outages %

Not Found Inspection 2,471 26% 19 0%

Nil Entry 2,268 24% 70 1%

Lightning 1,270 13% 2,206 19%

Elec Overload 939 10% 1,878 16%

Animal 541 6% 627 5%

Bird 437 5% 2,072 18%

Malfunction 309 3% 2,251 19%

N/A 223 2% 70 1%

Employee Accidental 218 2% 96 1%

Customer Side Fault 190 2% 193 2%

Successful Reclose 135 1% 565 5%

Corrosion/Infest 107 1% 131 1%

Vehicle Impact 90 1% 217 2%

Human Accidental 68 1% 26 0%

Loose/Poor Conn 68 1% 280 2%

Tree Clearing 39 0% 0 0%

Fallen Tree 32 0% 108 1%

False Call 28 0% 41 0%

Rot/Decay 27 0% 118 1%

Clashing 26 0% 101 1%

Storm Activity 26 0% 64 1%

Cut tree 21 0% 18 0%

Pollution – Salt/Dust 19 0% 174 1%

Vibration 11 0% 59 1%

Fire 8 0% 93 1%

Dug-Up 2 0% 37 0%

TOTAL 9,573 100% 11,514 100%


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Table 10.2.2 Powercor Comparative Analysis of 1998 and 1999

1998 1999Causes

Number ofIncidents

% Number ofIncidents

%

Malfunction 2,033 19.29% 1,986 19.88%

Bird 1,899 18.02% 1,878 18.80%

Elect Overload 1,894 17.97% 1,626 16.27%

Lightning 1,553 14.73% 2,014 20.16%

Animal 628 5.96% 583 5.83%

Succ Reclose 580 5.50% 562 5.62%

Pollution 383 3.63% 174 1.74%

Loose/Poor Connection 282 2.68% 216 2.16%

Rot/Decay 209 1.98% 111 1.11%

Fire 200 1.90% 84 0.84%

Vehicle Impact 154 1.46% 207 2.07%

False Call 131 1.24% 30 0.30%

Corrosion/Infest 129 1.22% 72 0.72%

Fallen Tree 123 1.17% 94 0.94%

Clashing 80 0.76% 88 0.88%

Human Accidental 58 0.55% 23 0.23%

Vibration 57 0.54% 53 0.53%

Empl Accidental 51 0.48% 83 0.83%

Vandalism 43 0.41% 27 0.27%

Bark 19 0.18% 21 0.21%

Cut Tree 16 0.15% 15 0.15%

Dug Up 15 0.14% 34 0.34%

Not Detailed 4 0.04% 11 0.11%

Cust Side Fault - 0.00% - 0.00%

N/A - 0.00% - 0.00%

Not Found Insp - 0.00% - 0.00%

Storm Activity - 0.00% - 0.00%

Tree Clearing - 0.00% - 0.00%

Total 10,541 100.00% 9,992 100.00%

10.3 FEEDER RELIABILITY MODELLING

10.3.1 Powercor has developed a model to assist in the determination of appropriate investmentprogrammes to achieve feeder reliability improvements50. In order to achieve a desiredoverall CMOS performance improvement, specific improvement targets for urban, shortrural and long rural feeders are set annually.

10.3.2 Given a required performance improvement within a particular feeder class, Powercoraim to achieve desired savings in CMOS through reducing both planned and unplannedoutages. Strategies for planned work include liveline work, automation and improvedprocesses. Strategies for unplanned work are considered in terms of controllable anduncontrollable factors. The unplanned uncontrolled causes, weather, storm and lightning

50 Document P122 Description of “The Model Output version 2”


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can be mitigated against in the longer term with some specific actions such as improvedlightning protection as detailed in section 8.6, additional attention to these should beundertaken. Unplanned controlled causes are malfunctions, birds, pollution andelectrical overload. These are all aimed at reducing the number of outages, not theduration of them. A plan should also be developed to reduce the duration of the outages.

10.3.3 Strategies for reducing unplanned controlled feeder CMOS are identified using areliability model. Given a desired performance improvement target for a feeder class(urban, short rural or long rural), the unplanned controllable events for a particular yearare ranked by their greatest contribution to CMOS irrespective of the cause (eg bird, polefire).

10.3.4 In developing the list of feeders for consideration using the model, only the data for theprevious year is used. For example, the feeders to be targeted in 2000 were selectedbased on 1998 data (1999 data was not available in 1999 when the feeders to betargeted in 2000 were identified). The process does not consider trends in performanceover previous years. This method of selection could lead to “reactionary management”,rectifying the problems that have just occurred and not considering more broader trendswhich if address, could lead to more sustained performance improvements.

10.3.5 Once the list has been established using the reliability model for the particular feedertype (urban, short rural and long rural), it is then reviewed to ensure that feeders of asensitive nature (where there have been political concerns raised or significant customercomplaints) are also included. A list of feeders requiring attention is then produced.

10.3.6 Powercor have established a range of costs51 to rectify particular unplanned controllablecauses for the various classes of feeder. These costs are applied to the list of feedersthat require attention to achieve the desired CMOS savings.

10.3.7 The costs are based on previous experience in fixing that type of cause for that feederclass (eg. birds on rural feeder). For example to address a bird problem on a ruralfeeder, Powercor assume that bird covers will need to be fitted to 200 poles at a cost of$700 per pole. The approach does not take into account the length of the feeder or theextent for example to which bird covers have already been fitted to that particular feeder.Short rural and long rural feeders are treated on the same basis, even though theirlengths are not the same.

10.3.8 The reliability model ranks feeders in terms of greatest to least contribution to CMOSsaving. Powercor do not consider whether the same CMOS saving could be achieved byrectifying other problems at a lower overall cost. The model is still in development.

10.4 PROGRAMS FOR IMPROVING RELIABILITY

10.4.1 In Powercor’s 2001-2005 pricing submission a number of initiatives have been proposed.During subsequent discussions between the Office and Powercor, they have refined thereliability improvement expenditure over the 5 year period, adjusting the allocationsbetween the three classes of feeders (urban, short rural and long rural) although the totalexpenditure remains the same. Table 10.4.152 shows Powercor’s final proposedallocations for improving reliability.

51 Document P140 Excel spreadsheet Psolutionscosts52 Document P145 Overall expenditure allocation


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Table 10.4.1 Expenditure on Improving Reliability ($ 000's)

FeederType

1999 2000 2001 2002 2003 2004 2005 2001-5Total

Urban 916 1,112 870 870 870 870 870 4,350

Short rural 1,457 1,770 2,457 2,337 2,337 2,337 2,337 11,805

Long rural 1,790 2,174 32,83 2,943 2,943 2,943 2,943 15,055

Total 4,163 5,056 6,610 6,150 6,150 6,150 6,150 31,210

10.4.2 Table 10.4.2 shows the forecast reliability improvement resulting from this expenditure.The table also shows the estimated percentage increase in reliability from the base casewhere no expenditure on reliability improvement initiatives is incurred.

Table 10.4.2 Reliability Resulting from Expenditure

FeederType

SAIFIUnplanned

Mins

CAIDIUnplanned

Mins

SAIDIUnplanned

Mins

SAIDIPlanned

Mins

SAIDITotalMins

Urban 1.5 (12%) 67 100 (14%) 27 (7%) 127 (12%)

Short rural 1.8 (18%) 72 133 (18%) 60 (5%) 193 (15%)

Long rural 3.5 (15%) 94 322 (16%) 76 (6%) 398 (14%)

TotalNetwork 2.2 (15%) 82 182 (16%) 54 (5%) 236 (14%)

10.4.3 Table 10.4.3 shows the SAIDI improvements and the associated costs for the proposedreliability improvement option present in Powercor’s 2001 price review enhancedreliability submission. The SAIDI improvement change has been calculated on the basisof the total number of the customers on the network, not the number of customers in thefeeder class.

Table 10.4.3 Proposed SAIDI Improvements and Associated Costs

Feeder Type SAIDI Change(mins)

Cost ($ 000’s) Cost ($ 000’s)/minuteImprovement

Urban 17 9,925 584

Short rural 45 17,310 385

Long rural 69 18,075 262

10.4.4 It is interesting to note that expenditure per SAIDI minute saved for urban feeders isgreater than short and long rural feeders. It could be expected that greater expenditureon long rural feeders would be required given the lower customer density and thereforemore equipment changes at greater cost would be necessary to achieve the sameimprovement in SAIDI.

10.4.5 The logic of the model or the base assumptions would seem to be flawed. Afundamental issue with the model is that it assumes particular performanceachievements based on eliminating events that occurred in the previous year (which maynot have happened again in the following year anyway). The feeders investigated(Section 6) provides ample evidence of this.

10.4.6 In order to improve SAIDI performance either the number of incidents or the averagerestoration time needs to be reduced. The key Powercor initiative to reduce the numberof incidents is the use of automation. Automatic circuit recloser (ACR) devices are usedinstead of fuses. The use of ACRs automatically restores supply following transientfaults, which Powercor estimate to be 2/3 of faults experienced. Transient faults arethose where the fault cleared itself and restoration was possible without remedial work.


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10.4.7 Powercor are also increasing their ability to rapidly isolate the smallest faulted section ofa line through the use of remotely controlled switches and control schemes (SCADAsystem control and data acquisition) in order to reduce interruption durations. Thisinitiative is outside the capabilities of Powercor reliability model.

10.4.8 Local service agents are also been utilised in remote locations to reduce the travel timeassociated with attending and repairing faults in rural areas.

10.4.9 Powercor have also adopted a supply reliability improvement strategy (SRIS) thatinvolves targeting poor performing feeders in sensitive areas that have a short-termdownturn in performance. Powercor intend to carry out special inspections aimed atdetermining the primary cause and implementing programs to correct these causes. Thisappears to be a new initiative to counter adverse publicity, particularly in the Geelongarea, as no examples of specific inspections and resulting programs carried outpreviously were identified as part of this investigation. It is also an initiative that requiresa greater responsiveness to trends within the outage data than is apparent withinPowercor. Table 10.4.4 shows the intended reliability improvement strategies and theassociated expenditure over the period 2001 to 2005.

Table 10.4.4 Summary of Reliability Improvement Programs ($ 000's)

Strategy Expenditure

Specific feeder investments 22.0

Automation 5.5

Fault indicators 0.75

SRIS 2.5

DCI sentry 0.46

Total 31.21

10.4.10 Specific feeder investments are those carried out following the analysis using thereliability model. Other initiatives are evaluated through individual proposals.Automation involves the fitting of automatic reclosers

10.4.11 Business cases examined as part of this investigation included: -

• SWER ACR (automatic circuit recloser) programme – year 2000 networkperformance53

• Fault indicator installation54

• Auto reclose monitoring (stage II) using DCI sentry system55 [P55]

• Other projects

These are discussed in detail below.

SWER ACR programme

10.4.12 On SWER (single wire earth return) systems Powercor’s usual practice is to install anexpulsion dropout fuse on the first pole after the SWER isolating transformer to protectthe line. Powercor has found that two out of every three faults that cause the fuse tooperate are transient in nature. An ACR can discriminate between transient andpermanent faults and can result in 90% of transients being restored without the need forline crews to attend. The ACR also enhances fire mitigation by eliminating the use ofexpulsion drop out fuses. Drop out fuses are more prone to starting fires.

53 Document P53 Business Case for SWER ACR Program – Year 2000 Network Performance54 Document P54 Business Case for Fault Indicator Installation 200055 Document P55 Business Case for Auto Reclose Monitoring (stage II) using DCI Sentry System


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10.4.13 Powercor have a total of 1,151 SWER systems supplying 36,000 customers. A programwas commenced ten years ago by SECV and so far ACRs are installed on 506 of theseSWER systems, the initial focus being on concrete pole SWER lines. In 2000 Powercor,plans to install a further 50 ACRs with SWER systems being selected on the basis ofwhether the lines are concrete pole, as well as the number of customers serviced andthe travel time from the nearest depot.

10.4.14 The business case shows a payback of 6 years and internal rate of return in the order of33%. This program is intended to take a further 13 years to complete if all SWER linesare to have an ACR fitted. The cost for installing 50 ACRs is $275,000. The program in2000 is expected to reduce rural CMOS by 1.11 minutes. A further 50 ACRs per yearare planned to be installed over the following four years of the price review period, withthe total five-year project cost being $1,375,000.

10.4.15 Given the high internal rate of return, an enhanced program would seem to be justifiedwith the program duration reduced back considerably from the 13 years proposed.

Fault indicator installation

10.4.16 Fault indicators provide an indication whether a fault current has passed through them.Placing these indicators at strategic locations will enable fault crews to more readilyidentify which section of a line a fault is in and hence reduce the time taken to locate afault and restore supply. The project involves installing 175 pole-mounted indicators onthe worst feeders.

10.4.17 The cost to install 175 devices is $150,000. This is planned to be completed byDecember 2000. These devices would have an increased benefit if they were installed inassociation with automated switches. Powercor has not demonstrated the economicbenefits as they maybe difficult to quantify. The following rudimentary analysis showsthat these devices may offer a superior reduction in SAIDI minutes per dollar spent thanother initiatives proposed by Powercor.

10.4.18 It is assumed that 1,750 fault indicators (approximately ten per feeder) are fitted to thelong rural feeders. This results in a saving of 4 minutes per interruption (throughoperatives being able to more quickly locate the fault and return the rest of the feeder toservice). With an average of 4.1 interruptions per year per long rural feeder, this wouldresult in an overall system reduction of 5.2 SAIDI minutes. This could be achieved at anoverall cost of $1.5m or $300,000 per minute saved; better than the investmentsidentified in Table 10.4.3.

10.4.19 A coincident training of fault repair staff would be necessary, as they do not currentlyutilise the few similar devices already installed.

Power supply monitors

10.4.20 Power supply monitors are intended to be installed at customer premises downstream ofline reclosers to monitor outages and report back via the customers telephone line.When the monitor detects a power outage or out of specification voltage condition, theremote device reports this information to a central location after a pre-set time.

10.4.21 The exact locations have not been determined for the monitoring devices but it isintended to install 700 devices at a total cost of $960,000.

10.4.22 These devices will not directly result in any improvement in reliability.

Daylesford modifications

10.4.23 Daylesford is presently fed from Ballarat across the Wombat state forest which results ina high exposure to outages on feeder BAN008. A significant proportion of the load onthis feeder is 50 km from the zone substation. Powercor are proposing to provide analternative supply from Castlemaine to reduce the impact of outages,


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10.4.24 Load growth on this feeder is 4% and the line is loaded to 88% of capacity, which willrequire upgrading within 5 years. The customers supplied are high tourism, spa centre,commercial organisations and woollen and timber mills.

10.4.25 Customer complaints from this feeder represent 8% of the total unplanned outagecomplaints for Powercor.

10.4.26 Although load growth will not result in a requirement to reinforce the feeder for at leastfive years, Powercor are to spend $1.3m to create an alternative supply to Daylesford.The advancement of the work is in response to the poor reliability being achieved.

Geelong pole fires

10.4.27 Geelong had 226 power interruptions56 during December 1999 and January 2000. In thefirst four months of 2000, there were 64 pole fires, compared with 54 for the whole of199957. Powercor carried out thermal imaging to detect hot spots and uncovered 25major faults and 126 other faults58. Powercor have embarked on $2m of works from Aprilto August, covering substations in Geelong and Wauran Ponds with three full time crews.

10.4.28 In May, Powercor received a report commissioned as a result of these incidents59. Anoverview60 of this work has been examined. The report focuses on feeder DDL23 thatoriginates in the Drysdale zone substation (on Bellarine Peninsula) and feeder WPD22that originates at Wauran Ponds zone substation.

10.4.29 Powercor advise in this report that one of the factors that contributed to a worsening ofsystem reliability over the years is that much of the network is still the originalconstruction (30 to 50 years old). Powercor have addressed the increasing rate of failureby the cyclic inspection program, which has substantially eliminated failures of woodpoles and has, for the last two years incorporated a capability of detecting crackedinsulators, broken ties etc. Other failures are prevented by the selective reconstructionand repair programs carried out in areas where failures have already been recorded.

10.4.30 Powercor state in their overview of the Geelong Pole Fire report that their inspectionprogram has not addressed the deterioration of electrical connections. Infra redthermography partially addresses this by detecting connection hot spots.

10.4.31 The overview of the Powercor investigation states that the general impression was thatthe backbone structures do not widely exhibit the common signs of neglect in the form ofloose attachment hardware, leaning insulators and broken ties. However, the lines areold and still retain a lot of old (more than 40 years) components.

10.4.32 Powercor state that the most common repair required is the replacement of crackedinsulators. The great majority of the cracked insulators are brown glaze porcelain ones –now more than 35 years old, as the SECV changed to grey porcelain in the mid 1960s asa means of reducing visual impact of overhead structures.

10.4.33 The causes of this defect are a complex interaction of the detailed manufacturingprocess of each batch of insulators, and particularly between different suppliers andcorrosion caused by the local atmosphere. Powercor advises that the manufacturingbatch almost certainly has an influence on the probability of cracking, because of thelocalised nature of groups of cracked insulators.

56 Document P34 Editorial Geelong Advertiser 12 April57 Document P112 Geelong Advertiser 3 May 200058 Document P34 Geelong News 4 April 200059 Document P112 Gelong Advestiser 3 May 200060 Document P145 Overview report on 22 kV feeders DDL23 and WPD 22


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10.4.34 Powercor are proposing the following initiatives to reduce the number and severity offaults: -

• Eliminating loose hardware on all pin insulator structures as the most achievablemeans of minimising pole and cross-arm fires

• Ensuring that poles with difficult access receive appropriate attention, (a pole thatrequired multiple gate access was found to have all three insulators cracked

• The report advised that DDL23 feeder has unsatisfactorily designed pin insulators on47% of the 523 poles inspected and these need to be replaced on the extremecoastal fringe by self-cleaning aerodynamic profile insulators

• The old design of pin insulator suffers a variable incidence of cracking, which mustincrease the incidence of pole fires. The cyclic inspection currently in hand on DDL23is the first time the feeder has been checked since the introduction of stabilisedbinoculars two years ago and so the incidence should be expected to reduce in thenear future.

• At extremely exposed locations, less than 500m from the foreshore, high reliabilityprotection from pole fires can only be achieved by improving the effectiveness of theinsulators. This requires the replacement of the insulators with modern designs

10.4.35 In discussing the conclusions of their overview of the investigation, Powercor MarketStreet Maintenance staff stated that they are not spending “extra” money in Geelong butmoving forward inspections. Overall, the maintenance costs are expected to be thesame while carrying out this additional Geelong work, as they will not be spending asmuch elsewhere.

10.4.36 It is unclear how these feeders did not receive adequate inspections. It is of concern thatthe recent inspection is the first time the feeder has been inspected effectively.

10.4.37 Powercor consider that their maintenance standards and inspections are appropriate butthat local problems can occur. For example, there were only pole fires in one area butthey have similar poles in the similar environments further down the coast, which did nothave pole fires.

10.5 POWERCOR’S SUPPLEMENTARY SUBMISSION

10.5.1 On 20th April Powercor, provided a supplementary submission to the Office as part oftheir 2001 Electricity Distribution Price Review61. Table 10.5.1 shows the expenditureproposed on further enhancing reliability work over and above the reliability improvementcase in the original submission.

61 Document P95 Powercor Supplementary Submission to the Office 20 April


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Table 10.5.1 Supplementary Submission Reliability Improvement Expenditure ($000's)

FeederType

2001 2002 2003 2004 2005 2001-5Total

Urban 1,400 1,400 1,000 925 850 5,755

Short rural 1,400 1,400 1,000 875 830 5,505

Long rural 800 800 520 500 400 3,020

Total 3,600 3,600 2,520 2,300 2,080 14,100

10.5.2 This additional expenditure of $14.1m is planned to achieve a SAIDI reduction of 16minutes. The previous improved reliability case in the original submission proposed aSAIDI reduction of 37 minutes for an expenditure of $31.2m. The additional expenditureequates to $0.88m/minute compared with $0.84m/minute in the original submission.

The additional works proposed include: -

• Further investment in Geelong area to reduce risk of pole top fires ($9.5m)

• Replacing additional pole top structures in Wimmera region ($1m)

• Installing new feeders in Laverton, St Albans and Wirribee regions ($0.7m)

• Automation in Sunshine region ($0.8m)

• Upgrading poor performing 66 kV radial feeders ($0.4m)

• Fitting additional bird guards in Terang region (0.34m)

• Additional investments in Warrnambool, Hamilton, Koroit, Portland and Woodend($1.3m)

10.5.3 Unlike the reliability improvement initiatives in the original submission, the supplementarysubmission lacks the same degree of rigour. A number of the projects classified asreliability improvements are equivalent to enhancements and should not have beenclassified as reliability improvements. Other projects are effectively maintenance, whichshould have been carried out, as the assets did not satisfy maintenance standards. TheGeelong report supports this where it stated that this was the first time that feeder DLL23had been checked effectively. When inspected, is the work found reliability type work ormaintenance that should have been carried out previously?

10.5.4 However maintenance replacement requirements included in the price review submissionallowed for replacement of assets due to age and condition only. Replacement of pininsulators because they present a pole fire risk is driven by a design defect, rather thanby age and condition.

10.5.5 The basis for determining the SAIDI savings is unclear. There has been no breakdownof the SAIDI savings into urban, short and long rural. When PB Power discussed theoriginal submission reliability improvements with Powercor, the basis of the calculationswas readily available. When the supplementary submission was received on 28th April, arequest was made for the supporting calculations and we were advised that they wouldtake a week to produce. They have not yet been provided.

10.5.6 While the $/SAIDI minute saved are comparable for the two options, it is unclear how thesupplementary submission SAIDI was calculated. One option would have been to prorata the proposed expenditure. In the original pricing submission, a graph (chart 15)shows the variation in SAIDI with expenditure. It is unclear if Powercor knows which partof the curve they presently are on.


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10.6 EFFECTIVENESS AND MONITORING OF RELIABILITY IMPROVEMENT INITIATIVES

10.6.1 In Figure 10.6.1, the change in SAIDI from 1997 to 1999 is shown against the averagemaintenance replacement CAPEX 1997 and 1998. Those feeders with improvedperformance are between 0 and 1 on the change in SAIDI axis, with those that havedeteriorated shown as a negative number. Highlighted are some of the feeders selectedfor this investigation. Those feeders not identified are in with the bulk of the feeders atthe left of the graph.

10.6.2 The graph shows that there is not a strong correlation between the expenditure on thefeeder and a resulting improvement in performance, although there clearly is some withno feeder performance deteriorating significantly more than a factor of 3 times aftermoney had been expended on the feeder. Figure 10.6.2 is the central section of Figure10.6.1. The apparent random improvement of many feeders irrespective of the amountof money spent on the feeder indicates either that other activities took place on thesefeeders to improve performance or more likely that the randomness to performanceimprovements and deteriorations is significant.

10.6.3 There are a number of feeders where significant expenditure has been made but theperformance has deteriorated. The figures show the difficulty Powercor has in targetingexpenditure. They are aware of the problem, but it is difficult to know where to start. Themodel is a start in developing a structured approach but there needs to be greater in-depth analysis as has been carried out in this investigation. A further consideration isthat data over a longer period of time needs to be reviewed to ensure the correct trendsare being identified. The trend line indicates that spending small amounts of moneydoes improve performance, but spending more money has little further impact.

Figure 10.6.1 Change in SAIDI against Maintenance CAPEX Replacement

Change in Performance against historical Maintenance Expenditure

-15

-14

-13

-12

-11

-10

-9

-8

-7

-6

-5

-4

-3

-2

-1

0

1

0 5 10 15 20 25 30 35 40

Ave Maintenance spend ($k/km) in 97 and 98

Ch

ang

e in

SA

IDI

((19

97-1

999)

/199

7)

Best fit Curve(Least Squares)


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Figure 10.6.2 Change in SAIDI against Maintenance CAPEX with Reduced Scale

-3

-2

-1

0

1

0 10

Ave Maintenance spend ($/km) in 97 and 98

Ch

ang

e in

SA

IDI

((19

97-1

999)

/199

7)

SU005

10.6.4 Powercor has Technical Officers who monitor incidents on a day to day basis as well asSAIDI/SAIFI/CAIDI on regular basis. The top 10% worst performers are considered indetail including how they contribute to overall performance.

10.6.5 The approach to targeting which feeder to refurbish and add remote control is basedupon overall feeder performance. It is understood that Powercor do not presently trendthe cause of faults over time. This would assist in establishing underlying factors to takeinto account when determining appropriate reliability improvement programs.

10.6.6 Powercor need to take a more structured approach to monitoring performanceimprovement expenditure to ensure that programs achieve the maximum cost benefits.


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11 EFFECTIVENESS OF BUSINESS PROCESSES ON SYSTEM RELIABILITY

KEY POINTS

Powercor would benefit from the utilisation of an Asset Management Plan. Theplan would effectively communicate and link corporate goals to asset managementactivities and provide a framework for reviewing the effectiveness of asset management.

Section 11.2

All the benefits are not being obtained from major IT investment. Powercor haveextensive and recently installed IT systems, with business rules locked in. The fullbenefits of these investments have yet to be realised. The business is informationtechnology driven. More cost benefit analysis should be considered.

Section 11.2

The asset performance measures used to run the business are limited. Powercoruse only a few of the extensive range of Key Performance Indicators they have defined.Those that are used provide an incomplete picture of the effectiveness of assetmanagement.

Section 11.3

Customer satisfaction monitoring is not effective. Customer satisfaction is monitoredwith independent surveys, which are not monitored on a feeder or area basis. Powercorrely on customer complaints and media enquires for localised feedback. The Companyis aware that they need to improve their customer communications and move away fromthe present reactive approach.

Section 11.4

11.1 OVERALL PERFORMANCE

11.1.1 Powercor has an unplanned reliability performance comparable to similar distributionbusinesses. It is better than some perceive. However, planned SAIDI is poor.

11.1.2 Powercor advises62 that they have improved operational efficiency through three keyinitiatives: -

• Restructuring at a Divisional level into an Asset Owner and Service Provider structure

• Introducing a new asset management IT system (SAP R3) for which Powercor hasacknowledged the full benefits are yet to be achieved

• The introduction of Reliability Centred Maintenance. RCM allows Powercor to modifymaintenance practices without impacting on performance or increasing the risk to thecompany.

11.1.3 Pacific Economics Group undertook a benchmarking study that investigated Powercor’sefficiency. This efficiency study63 compares Powercor to a range of US companies usingeconometric modelling. The study concludes that Powercor’s cost performance issuperior to that of a US utility facing the same business conditions. The authors notethat this difference is not statistically significant and Pacific Economics Group cannottherefore reject the hypothesis that Powercor is an average cost performer. Thestatement is made in the executive summary that “Powercor’s reliability performance istypically above that of an average US distributor”. However, in the report, the average

62 Response from Powercor Network Performance Manager to question as to why Powercor has improved

operational efficiency63 Document P114 Powercor performance : Results from International Benchmarking


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US all utility SAIDI is quoted as 59.6 and SAIFI as 0.74. The equivalent Powercorindicators are 207 and 2.3 based on the Powercor Price Review submission. This issignificantly worse than the average for all US utilities.

11.1.4 In summary, the Pacific Economics Group benchmarking study contains inconsistenciesand does not show Powercor to necessarily be a better performer than US distributors.In particular, overall network SAIDI is significantly worse than the US average.

11.2 PEOPLE AND PROCESSES

11.2.1 Powercor is a process-based organisation with staff located in several different offices.The technical staff in the field have an excellent knowledge of the assets. However, dueto the dispersed location of the key process leaders across the company, it is unclearwhether optimal decision making always occurs.

11.2.2 The business runs using processes displayed succinctly with diagrams and workinstructions. The process diagrams describe whom to talk to about what, but not whatthe company policy is. There are many process maps describing the interrelationshipsbetween the various process activities. The process structure has been in place for 2½years but the process guide64 documents are still in draft form.

11.2.3 In visiting various field locations, it was evident that the information in the field was notalways consistent with that in Market Street. PB Power was advised that the informationfrom Market Street was the correct view. We were advised, for example, that the localservice agent scheme was working well. However, given the reports we were given byseveral sources in the field, this appeared not to be the case in at least one area.

11.2.4 At times, we also found difficulty in discussing a particular feeder with someone who hada comprehensive knowledge of it. In one case locally based staff knew all about themaintenance aspects of a feeder, but could not discuss the feeder performance. In fact,they were unaware of any particular feeder problems that had occurred.

11.2.5 Powercor is heavily dependent on IT technology. In recent years, they have installed thefollowing systems: -

• Customer information system (October 1999 $17m)

• Outage management system (November 1999 $5m), not fully functional in May 2000

• GIS (1999 and 2000 $7.5m)

• SAP (1997-98 cost is not known but further upgrade planned for 2000)

11.2.6 Powercor are very dependent on SAP to manage their assets, with all the business rulesbuilt in. However, the capabilities of SAP are limited in some instances. For example,staff establishing what the planned maintenance should be down load inspectioninformation from SAP to PC, to carry out detailed analysis.

11.2.7 SAP is also used to monitor inspectors and run ad-hoc queries on asset defects.Powercor are considering matching outage causes in OMS (the new OutageManagement System) with SAP defect information.

11.2.8 Powercor have only recently started recording maintenance costs at location level and,until now, been unable to analyse costs on a per feeder basis.

11.2.9 Powercor do not have an integrated asset management plan that: -

• Links asset management strategies to corporate goals and has clear accountabilities

• Describes asset management systems and information

64 Document P73 Notes on Process Diagrams


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• Provides a clear view of assets, their location and condition

• Details proposed service levels with customer orientated reliability, security andavailability performance targets along with justifications

• Describes network development and life-cycle asset management plans

• Describes risk policies and their application

• Evaluates performance against the plan (physical and financial), targets anddiscusses the differences

11.3 MONITORING AND COMMUNICATION

11.3.1 Powercor’s Asset Management Strategy65 Appendix I has a list of 50 key performanceindicators that can be used to monitor asset performance. However, very few areincluded in the two monthly Network Business Reports reviewed. Benefit would accrueto Powercor through the application of more key performance indicators.

11.3.2 The monthly Network Business Report66 monitors shareholder value, customers andcommunity, employees and network key issues. Costs are considered by key function(faults, line inspection, vegetation etc.) and also by budget areas. Supply reliability andcustomer satisfaction is the key elements under customers and community

11.3.3 While Powercor has an extensive amount of data and an extensive range of KPIsdefined, they do not appear to have a comprehensive reporting system to ensure thattheir assets are being effectively managed.

11.4 CUSTOMER SERVICE

11.4.1 Customer satisfaction is monitored by the use of customer surveys. For example anumber of customers who experience an unplanned outage are approached to establishtheir response regarding Powercor’s performance. Powercor do not obtain surveyinformation on a geographical or feeder basis and rely on customer complaints to providelocalised feedback.

11.4.2 Powercor have a range of customer service standards and guaranteed service levels,several of which have been in place since SEC days. Powercor are planning toimplement a new guarantee scheme to make payments to customers whose supply hasnot been restored within an agreed time after a fault. It is proposed that, if supply is notrestored within 12 hours, residential customers will receive $50 and commercialcustomers $100.

11.4.3 Powercor has made some improvements and is aware that they need to improve theircustomer communications with local customer groups. It is feasible at a relativelymodest cost for the distributor to implement an open access same-time informationsystem (OASIS) and appropriate standards of conduct similar to the requirementsreferred to in Federal Energy Regulatory Commission rule 889 for transmission systeminformation. This would benefit the Internet savvy customer by giving greater informationas to the nature and location of the fault. This maybe of interest to a few, but mostcustomers are likely to be more interested in knowing when the power is going to beturned back on and would prefer Powercor to concentrate on avoiding faults in the futurerather than providing additional technical information about the current fault.

65 Document P40 Asset Management Strategy66 Document P127 March 2000 Network Business Report


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12 POTENTIAL RELIABILITY TARGETS

KEY POINTS

No changes should be made to the Distribution Code in the short term. Thereliability improvement incentives and guaranteed service level payments proposed in theDraft Decision should be introduced and evaluated first. Section 12.1

The additional costs of reporting on an individual customer basis are justified.Reporting on the basis of the feeder average hides the reality of some customersencountering more than three times worse than reported average reliability.

Section 12.1

Short-term reductions in outage times could be achieved with improved faultmanagement procedures. This is considered a low cost and relatively quick means toreduce outage times by a small but effective amount. Section 12.3

Additional expenditure on maintenance of the low reliability feeders is viable andshould be undertaken. Reliability modelling indicates a 43% reduction in outages onthe low reliability feeders could be achieved with the expenditure of $96,000 per feeder.

Section 12.3

The fitting of remote operation of switches is a viable way of reducing total CMOS.Reliability modelling indicates that a 14% reduction in outage duration on the lowreliability feeders could be achieved with the expenditure of $255,000 per feeder.

Section 12.4

The expenditure of $22.1m would result in more homogenous network reliability.Reliability modelling indicates that an 11% overall reduction in CMOS will result if thisexpenditure is targeted at 34 low reliability feeders. No feeder would then have a level ofreliability more than 2.1 times the average.

Section 12.4

12.1 OBJECTIVES AND FOCUS OF REVISIONS TO RELIABILITY TARGETS

12.1.1 Section 4.5 of this report has shown there is a large variation in the reliability of theelectricity supply to customers of Powercor. Significant numbers of urban, short and longrural feeders supplying customers of Powercor have a low level of reliability. Currentlythere are no requirements relating to the minimum level of reliability of supply toindividual customers. The current minimum standard of reliability required by theDistribution Code specifies average performance and, as concluded in Sections 3.4 and12.1 of this report, is easily achieved. Nevertheless, the publication by the Office ofdetails of poorly performing feeders has been effective in raising the reliability of supplyto some poorly served customers, although overall there has been no reduction in thenumber of poorly served customers (Figure 4.5.5).

12.1.2 There are two weaknesses associated with the current approach. Firstly the reporting iseffective only through retrospectively embarrassing the Distribution Businesses.Secondly, it takes no account of the performance received by individual customers as allthe reporting is on the basis of the average reliability provided to customers on a wholefeeder. The compensation payment to customers and the ‘S’ factor adjustment to thedistribution price control as proposed in the Draft Decision67 can be expected to alleviatethese shortcomings and be effective at raising the minimum standard of supply only if thefollowing conditions are met: -

67 2001 Electricity Distribution Price Review, Draft Decision, May 2000


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1 The optimised cost to the customer of achieving the necessary improvements to afeeder is less than the value of the reduction in lost load resulting from theimprovement in supply reliability on that feeder. If this is not the case the reliabilityimprovement is uneconomic from a customer perspective

2 The long run cost of achieving the reliability improvements is lower than the full costof meeting payments to customers for failure to meet the specified levels plus the ‘S’factor effect (albeit small) on the distribution price

3 Reliability of supply is measured by exception on an individual customer basis.

12.1.3 This report recommends, that for the present at least, the s-factor incentive andguaranteed service level payments proposed in the Draft Decision are introduced andtheir effectiveness evaluated before any major structural change is made to therequirements in the Distribution Code. A single change, the introduction of a prescribedminimum level of service set either at a multiple of the standards in the Distribution Code(500 minutes for rural and 250 minutes for Urban), alternative predetermined levels, ormultiples of the achieved average performance could be introduced. This latteralternative would be the preferred change given that a requirement to ensure that nocustomer receives a level of reliability less than X times the average provided by theDistribution Business will ensure that the gap between average and worst performancedoes not deteriorate as average performance improves. However at this stage it isconsidered that no change should be made given that there are a number ofuncertainties associated with uniform pricing and the relative cost of supply to customersin different locations. In particular: -

1 The analysis of the Ballarat North long rural feeder BAN008 in Section 12.2 of thisreport, and the subsequent extrapolation of this analysis to the low reliability feedersacross the whole Powercor network in Section 12.6, indicates that the cost ofachieving a reasonable improvement in reliability is significantly less than the value ofthe lost load to customers.

2 It is not yet possible to determine whether the components of the ‘S’ factor and thelevels of the Guaranteed Service Payments will be set at an effective level in the FinalDecision.

3 The Draft Decision provides for compensation payments to be determined on thebasis of the reliability of the supply to individual customers. The following analysis ofthe feeder BAN008 supports this requirement.

12.1.4 The average number of interruptions and minutes off supply for each feeder are reportedby the Office for all feeders across the State of Victoria as part of the Office’s publicreporting. The reported figures though are an average, and on each feeder there will besome receiving a level of reliability better than the average, others a level below theaverage. In order to ascertain the actual level of service received by a customer from theOAS data requires information that relates the connectivity of the component parts of thenetwork to each other and thence to each customer. Powercor were unable to supplythis data in useable form. Therefore the modelling undertaken and referred to in thissection is in tow parts. A high-level multi component model (utilising series-parallelreduction techniques) of a Powercor long rural feeder and a full connectivity model of aTXU short rural feeder (the necessary data not being available from Powercor).

12.1.5 Figure 12.1.1 in this report shows the average number of minutes off supply encounteredby customers on the TXU short rural feeder over the three years, 1997 to 1999,reconstructed from the known position of customers on and the actual performance ofthe feeder. (Section 12.2 of this report describes the analysis of the feeder and therelevance of this feeder to the remainder of the reliability analysis in this report.) Thereare no reasons to believe that the distribution of good and poor performance will be anybetter on Powercor feeders.


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Figure 12.1.1 Customer Minutes Off Supply Relative to the Average

0.0

1.0

2.0

3.0

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

Customer Numbers as a % of the Total on the Feeder

To

tal D

ura

tio

n o

f O

uta

ges

Rel

ativ

e to

Fee

der

A

vera

ge

12.1.6 The shape of the curve is expected to be typical, with 45% of customers receivingaverage performance or better (1.0 on the vertical axis) around 10% receiving only 50%of the average number of minutes off supply. Five percent of customers receiving morethan 1.5 times the average and a few percent receiving up to three times the averageminutes off supply. A similar distribution curve is achieved for the number ofinterruptions encountered by customers. The distribution of customers relative to thelocation of faults affects the shape of the curve and is modified to a degree by thelocation of switching devices. The performance reporting undertaken by the DistributionBusiness and the Office ignores this variation in reliability that is superimposed on therange of reliability of the feeders. Some feeders have a level of reliability three times ormore lower than the average, on those feeders some customers will be receiving a levelof reliability nine times poorer than the average.

12.1.7 The level of detail held within the customer information and network information ITsystems renders it possible for Powercor and the other Distribution Businesses to reportthe level of reliability achieved on an individual customer basis. (Accepting that the LVphase connectivity is not known and therefore on those relatively rare occasions whenonly one phase supply is interrupted the data will be inaccurate.). This report considersthat the relatively modest cost of implementing such a system of reporting is justifiedgiven that the current reporting is not adequate to show actual reliability (more than 30%of customers receive reliability different to the average by more than 25%).

12.1.8 The costs to Powercor of implementing reporting on an individual customer basis willarise from minor modifications to existing software ($50k) and the implementation of adata transfer process to the Office ($10k).

12.1.9 The costs to the Office will arise from the need to automate the reception and analysis ofthe outage data ($80k) for individual customers (some form of unique identifier for thecustomer and location on a feeder) whose reliability falls below predetermined levels foreach feeder type. The optimum arrangement is likely to be that feeder reliabilitycontinues to be reported and individual customer reliability is reported on an exceptionbasis. It is not recommended that the Office be able to identify whether a specificcustomer is entitled to a refund, merely that the data is available for the extension of theOffices current reporting and monitoring role to include customer supply as well as feederreliability.


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12.2 MODEL OF POTENTIAL RELIABILITY IMPROVEMENTS OF BALLARAT NORTH FEEDER

12.2.1 The objective of modelling the feeders (a single feeder of the Powercor network, andsubsequently in greater detail. one of the TXU network) was to evaluate the level ofimprovement in reliability that could be achieved with a number of reliabilityenhancements. The enhancements evaluated were; changes to the feederarrangement; the fitting of additional or replacement equipment; and improvements to themaintenance of the existing equipment. The modelling was also used to determine theapproximate cost of achieving the improved performance. The amount of work requiredto develop the first feeder model limits the number that can be modelled for this report.Subsequent feeders could easily be modelled if the connectivity data was available. It isconsidered that such work would be of value to Powercor enabling it to better analysethe benefits of reliability improvement expenditure.

12.2.2 The feeder to be modelled was carefully selected to ensure that the results of theanalysis could be utilised across all the low reliability feeders in the Powercor network.The long rural Ballarat North feeder BAN008 was selected. Long rural feeders are thepoorest performing of all the three feeder types in the Powercor network. Furthermore,the causes of outages on this feeder were varied. This feeder is also one of the poorestperforming, therefore the cost of improving the performance is likely to be typical of thecosts of improving any low reliability feeder on the Powercor network.

12.2.3 Appendix D sets out the generic issues associated with reliability modelling. The modelof BAN008 utilised the OAS data supplied by Powercor to create a representation of thefeeder and the outages that have occurred on it between January 1997 and December1999. Analysis of the OAS outage data shows that the outages on BAN008 are largelydue to lightning, birds and animals and unknown/other causes as shown in Table 12.2.1.

12.2.4 Figure 12.2.1 is the reliability model representation of the feeder. It shows the structureof the feeder, the lengths of each section and the type of device that separates them andthe number of customers attached to each section. This structure was used in a twelvecomponent reliability model of the feeder. Before undertaking further analysis the modelwas proven by comparing the predicted reliability using failure rates with the actualreliability from the OAS data. The model predicted a SAID of 717 minutes whereas theactual for the past three years was 682. Similarly the model predicted a SAIFI of 7.4 andis very close to the actual for the past two years of 7.6; and the CAIDI (model of 97,actual of 88) was sufficiently close for the purposes of this investigation.

12.2.5 The model is of a high level and could be refined further if the following data were to bemade available: -

• Load flow results based on feeder MD at the zone substation CB with the loads indifferent switching zones, each major spur load and any major load point loadswith customer numbers of each section

• Load flow results similar to the above of all adjacent feeders and any feederswhich have the potential to be tied to BAN008

• Load duration curves of BAN008 and adjacent feeders

• Line lengths of switching zones and each major spur and conductor size

• Longer fault history of the feeder

• Failure rates for different components of Powercor lines

• Operating diagrams of the feeder and adjacent feeders

• Switching policy and repair times for different types of faults on the feeder


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Table 12.2.1 Causes of Outages on BAN008

1997 1998 1999

Cause >15068 Total >15068 Total >15068 Total

Animal 1 3

Bark 1 1 1 4

Bird 1 1 6 2 2

Clashing 1

Cust. Side Fault 2 3

Elec Overload 3 3 3 3

Empl Accidental 3 5 1 1 4

Fallen Tree 1 1

False Call 1 1 1 4

Fire 1 1

Lightning 1 5 5 6 15

Loose/Poor Conn 1 2

Malfunction 3 2 2 3 5

Not Found Insp. 7 10

Succ. Reclose 3 3

Unknown 3 6

Total 17 30 18 27 18 39

12.2.6 The following reliability improvement options were considered and modelled: -

1 Proposed tie line with feeder rearrangement as shown in Figure 12.2.3. The Spargospur will be tied in to another feeder and this spur along with the Balroad andLyonville spurs will be supplied from this feeder under certain outage conditions.

2 Reduction of the failure rate (excluding failures due to lightning). As more specificdetails were not available it was conservatively assumed that it may not beeconomical to reduce the effect of lightning but the failure rate due to other reasonscould be reduced by 50% through improved maintenance.

3 Reduction in average repair time if the repair time could be reduced by 30 minutes

4 Installation of up to four ACRs and four automatic switches at selected points. Figure12.2.2 shows one option considered, more practical alternatives were also modelledand clearly it is not possible to put four ACR’s in series.

5 Proposed tie line with Installation of ACRs and automatic switches at selected pointsas shown in Figure 12.2.4 (a combination of 1 and 4).

6 Installation of ACRs, automatic switches at selected points and reduced repair time (acombination of 3 and 4).

68 Refers to major outages, those that affected more than 150 customers.


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Figure 12.2.1 Base reliability model of long rural feeder BAN008

B A N 0 0 8 F e e d e r M o d e l f o r R e lia b ilit y A a n ly s is - Ex i s t i n g

S w z o n e N o c u s t L d ( k V A ) L e n . ( K m )

A 9 8 5 0 0 1 1 . 5

B 3 5 8 1 2 0 0 5

C 8 6 3 0 0 1 2

D 3 1 3 0 0 3 1

E 4 5 0 1 3 0 0 1 2

F 0 0 3

G 2 0 0 6 0 0 5

H 3 2 9 3 2 9 1 3 . 5

I 1 5 4 0 0 5

J 2 4 6 0 0 1 1 . 5

K 1 9 0 0 2 7 0 0 1 3

L 6 7 4 1 8 0 0 8

A

B C

D

EF

K

J

I

B A N 0 0 8

C B

B A N 1 1

B A N 0 0 9

N / O s w i t c h

A R

s w i t c h

f u s e A R

s w i t c h

A R

f u s e

f u s ef u s e

N / O s w i t c h


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Figure 12.2.2 Reliability Model of BAN008 - Option of Auto Reclosers and Remote Controlled Switches Fitted

B A N 0 0 8 F e e d e r M o d e l f o r R e lia b ilit y A a n ly s is - W it h A u t o R e c lo s e r s a n d R e m o t e c o n t r o lle d s w it c h e s


A 9 8 5 0 0 1 1 . 5

B 3 5 8 1 2 0 0 5

C 8 6 3 0 0 1 2

D 3 1 3 0 0 3 1

E 4 5 0 1 3 0 0 1 2

F 0 0 3

G 2 0 0 6 0 0 5

H 3 2 9 3 2 9 1 3 . 5

I 1 5 4 0 0 5

J 2 4 6 0 0 1 1 . 5

K 1 0 0 0 1 4 0 0 7

L 6 7 4 1 8 0 0 8

K 1 9 0 0 1 3 0 0 6

A

B C

D

EF

G

L

K

J

I

B A N 0 0

8 C B

B A N 1 1

B A N 0 0 9

N / O A S

A R

A R

A SA S A RA S

A R

A R

A RA S

N / O A S

K 1


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Figure 12.2.3 Reliability Model of BAN008 - Additional Tie Lines Installed

B A N 0 0 8 F e e d e r M o d e l f o r R e lia b ilit y A a n ly s is - T ie lin e O p t io n


A 9 8 5 0 0 1 1 . 5

B 3 5 8 1 2 0 0 5

C 8 6 3 0 0 1 2

D 3 1 3 0 0 3 1

E 4 5 0 1 3 0 0 1 2

F 0 0 3

G 2 0 0 6 0 0 5

H 3 2 9 3 2 9 1 3 . 5

I 1 5 4 0 0 5

J 2 4 6 0 0 1 1 . 5

K 1 9 0 0 2 7 0 0 1 3

L 6 7 4 1 8 0 0 8

A

B C

D

E

K

J

I

B A N 0 0 8 C B

B A N 1 1

B A N 0 0 9

N / O s w i t c h

A R

s w i t c h

f u s e A R

s w i t c h

f u s e

f u s ef u s e

N / O

T i e t o a a n o t h e r f e e d e r


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Figure 12.2.4 Reliability Model of BAN008 - Additional Tie Lines Plus Auto Reclosers and Remote Controlled Switches Fitted

B A N 0 0 8 F e e d e r M o d e l f o r R e lia b ilit y A a n ly s is - T ie lin e w it h A u t o r e c lo s e r s a n d r e m o t e c o n t r o lle d s w it c h e s O p t io n


A 9 8 5 0 0 1 1 . 5

B 3 5 8 1 2 0 0 5

C 8 6 3 0 0 1 2

D 3 1 3 0 0 3 1

E 4 5 0 1 3 0 0 1 2

F 0 0 3

G 2 0 0 6 0 0 5

H 3 2 9 3 2 9 1 3 . 5

I 1 5 4 0 0 5

J 2 4 6 0 0 1 1 . 5

K 1 0 0 0 1 4 0 0 7

L 6 7 4 1 8 0 0 8

K 1 9 0 0 1 3 0 0 6

A

B C

D

E

K

J

I

B A N 0 0 8 C B

B A N 1 1

B A N 0 0 9

N / O A S

A R

A R

A R A R

A R

A R

A SA R

N / O

T i e t o a a n o t h e r f e e d e r

N / O A S

K 1


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12.2.7 The results obtained in terms of the improvements in SAIDI, SAIFI and CAIDI for each ofthe potential means to improve the reliability were as set out in Table 12.2.2. Clearlythese are effective in different ways but the overall effect is to reduce the averagenumber of minutes off supply encountered by the average customer by between fourteenand seventy four percent. All of them bring about an improvement for all customers onthe feeder.

Table 12.2.2 Changes in Reliability with Various Improvments to Feeder BGE024

SAIFI69 CAIDI69 SAIDI69 SAIFI%

Improvement

CAIDI%

Improvement

SAIDI%

Improvement

Base case 7.4 97.1 717.0

Proposed tie linewith feederrearrangement

7.6 53.2 403.3 -3% 45% 44%

Reduction of thefailure rate

5.1 97.4 494.5 31% 0% 31%

Reduction inaverage repair time 7.4 79.4 585.7 0% 18% 18%

Installation ofACR’s andautomatic switches

7.0 87.9 614.3 5% 9% 14%

Tie line withinstallation of ACRand automaticswitches

7.0 26.7 187.6 5% 72% 74%

Installation ofACR’s and reducedrepair time

4.8 88.3 424.2 35% 9% 41%

12.2.8 The reliability spreadsheet model in addition to modelling the improvements in reliabilitydetermines the reductions in MWh lost or unserved energy, and the economic return ofthe improvements. Table 12.2.3 shows the reduction in the amount of electricity that isnot supplied with each of the alternative improvements based on the assumption that theaverage customer would have utilised electricity at the rate of 2.4 kW/hour had theoutage not occurred. (2.4 kW is the average consumption for all customers on thisfeeder and is largely consistent across all feeders.)

12.2.9 Economic theory backed with some considerable analysis and practical examples basedon the cost of small stand-alone generation systems supports the notion that a customeris prepared to pay a high price to avoid an interruption. The Value of this Lost Load(VOLL) is many times greater than the normal tariff paid by the consumer. Powercor inits submissions to the Office for the price review submitted an enhanced reliabilityproposal with an estimated cost of $4.55 per kWh of lost load saved (Draft DecisionTable 5.6). This figure is lower than the estimate from TXU ($6.47 per kWh). For thisanalysis a VOLL of a conservative $5 per kWh was utilised. This has been used inanalysing the relative merit of the potential reliability improvements on the feederBAN008 since a lower cost of reliability improvement will represent a more efficient useof reliability improvement expenditure than Powercor anticipates.

69 The SAIFI, CAIDI and SAIDI shown here exclude the influence of planned and uncontrollable outages


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12.2.10 Using the economic value of the reduction in lost load resulting from each improvementscenario and comparing this with the estimated cost of each approach results in thedetermination of a payback period or present value ratio (PVR). The PVR (calculatedwith a weighted average cost of capital of 8%.) after fifteen years is also shown in Table12.2.3. A value of greater than one indicates that the investment in the reliabilityimprovement is a lower cost means of bringing about the reliability improvement than themaximum a customer is prepared to pay and less than the cost of the reliabilityimprovements proposed by Powercor in its enhanced reliability case. Clearly the greaterthe PVR value the better the alternative from an economic perspective.

Table 12.2.3 Economic Effects of the Reliability Improvement Options Considered

LostMWhsaved

Cost ofoption

Value ofreduction inLost Load70

PVR71

Option 1

New tie line14.9 $540,00072 $74,300 1.2

Option 2

Reduced failure rate throughimproved maintenance

19.4 $96,00073 $96,000 1.0

Option 3

Reduction in average repairtime

11.6 $57,000 $58,000 1.0

Option 4

Installation of ACR’s andautomatic switches

8.9 $255,000 $44,000 1.5

Option 5

Tie line plus installation ofACR’s and automaticswitches

28.5 $795,000 $142,000 1.5

Option 6

Installation of ACR’s,automatic switches andreduced repair time

25.8

$255,000plus$57,000 perannum

$130,000 1.5

12.2.11 For all these improvements the PVR is positive, (the improvement will therefore be at nogreater cost than anticipated by Powercor in its supplemental submissions to theDistribution Price Review). The margin above the anticipated cost is relatively small andreflects the long rural, low customer density nature of the feeder selected. The costs ofimproving the reliability of other low reliability feeders will on average be no greater, andcan be anticipated to be less overall than those indicated here. Some of these reliabilityimprovements can be undertaken more easily and more quickly than others can.Powercor is implementing some of these improvements.

70 Calculated with VOLL at a conservative value of $5 per kWh71 Calculated on the basis of a 15 year PVR72 Based on costs and conductor lengths estimated by PB Power73 The maximum sustainable annual cost to achieve a 50% improvement in reliability from non planned or

uncontrollable outages


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12.3 SHORT TERM RELIABILITY IMPROVEMENTS

12.3.1 The findings of this investigation into the Operations and Maintenance issues are set outin Section 9 of this report. The analysis of the feeder BAN008 supports these findingsand gives a greater degree of confidence that the level of improvement assumed in theanalysis would be achieved in practice. Each of these strategies is discussed below.

Maintenance Issues

12.3.2 Short-term improvements could be made through improved vegetation management,animal and bird proofing of HV structures. Malfunction and electrical overload accountfor more than fifty percent of the outages on urban (Figure 4.4.6) and short rural feeders(Figure 4.4.4) and nearly forty percent on long rural feeders (Figure 4.4.3). Additionalexpenditure on maintenance would reduce the number of outages being initiated bythese controllable causes.

12.3.3 Feeder BAN008 has encountered a typical number of outages from all these causes inrecent years. The contention is that at a cost of up to $96,000 per year these outagescould be reduced by 50% through improved maintenance. Spending all the $96,000 onimproved substation maintenance should eliminate over a few years most of themalfunction and overload outages. A significant part of the problems with feederBAN008 result from difficulties with the protection settings of the ACR’s. These could beeliminated for a fraction of the proposed expenditure.

12.3.4 Tree trimming and improved bird and animal proofing could result in a further reductionon this feeder. Bird proofing has largely been completed on BAN008. Animal proofing ofHV structures costs less than $3,000 fully installed so more than 30 such structurescould be completed every year. On other feeders inspected during this investigationwhere there were still many structures without bird proofing and the maintenance wasover a lower standard (Geelong 022) a large reduction in these outages could beexpected.

12.3.5 Table 9.2.3 shows that Powercor currently spend around $300 per km on maintenanceon long rural feeders. The feeder BAN008 is 370 km long and therefore current averageannual spend on this feeder is $111,000. The additional $96,000 proposed is thereforean eighty six percent increase and can reasonably be expected to have a very significantimpact on the feeder reliability within one or two years.

Operational Issues

12.3.6 Better fault restoration procedures were also identified in Section 9 of this report as apotential short-term means to improve reliability. This would not reduce the number ofoutages occurring but could result in a quicker return to service. The development offeeder restoration procedures has already been highlighted as a means to achieve a lowcost and quick reduction in the duration of outages.

12.3.7 The advantage of shorter outage times is adequately demonstrated by the modelledoption to reduce the average repair time. A 30 minute reduction in repair time is valuedat $58,000 per year for the feeder BAN008. The average duration of a fault across thewhole network in 1999 was 87 minutes. If the utilisation of better fault managementprocedures could reduce that by just one minute, a 1% reduction in CMOS of the feederwould be achieved at a minimal cost. An alternative way to produce shorter outagetimes is to fit more remote or automatic switches; the benefits are of a similar magnitude.Given the design and installation lead-time the benefit of these is unlikely to be seen inthe short term, they are therefore considered further under medium term improvements.

12.3.8 Reductions in the outage duration with improvements in the speed of response ofPowercor staff by having more staff available at times of high work load is likely to bejustifiable if this can be done in a low cost way. The re-introduction of fully staffedPowercor depots in remote areas will not be viable. Extension of the Local ServiceAgent arrangement should cost less than $58,000 per low reliability feeder. It should


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therefore be investigated further. Reductions in the outage duration through improvedmaintenance techniques and making temporary restorations should not be overlooked.

12.3.9 Section 10.4 of this report sets out Powercor’s programme for the fitting of faultindicators. The fitting of ten of these to a feeder at a one off cost of less than $10,000 isanticipated to reduce the average outage duration by four minutes. It easy to see thatthe remaining $48,000 from the first year plus a few subsequent years could achieve areduction approaching 30 minutes.

12.4 POTENTIAL SHORT TERM IMPROVEMENTS

12.4.1 There is the potential to improve the reliability still further through the combination of bothincreased maintenance expenditure and shortened outage times. This is option 6 asshown in Table 12.2.2 and Table 12.2.3. This option requires a capital expenditure of$255,000 and permits an annual expenditure of $58,000. An improvement of overforty-percent in SAIDI is considered achievable through these means. This is sufficientto improve even the poorest performing feeder to a level of reliability less than threetimes poorer than the average and nearly all feeders to within twice the average.

12.5 MEDIUM TERM IMPROVEMENTS TO LOW RELIABILITY FEEDERS.

Installation of Ties to Other Feeders

12.5.1 BAN008, and a number of other feeders, has few interconnection points to other feeders.This option proposes the installation of a tie to another feeder which could be used toprovide a supply to a part of the feeder BAN008 in the even of a fault occurring part waydown the feeder. BAN008 and most long rural feeders and a large number of short ruralfeeders in the Powercor network consists of a long backbone with short spurs from it.Faults on the backbone render it impossible to deliver electricity to customers beyond thefault unless there is an alternative interconnection from an adjacent feeder.

12.5.2 The costs of installing a tie line are very specific to the particular feeder and the locationof adjacent feeders. It is accepted there are some feeders in the Powercor network thatwould require extensive new lines to be built to achieve an interconnection. For thisanalysis, it was assumed that the tie would require sixteen kilometres of new line to beconstructed and forty kilometres of existing line to be re-conductored with wire of asufficient capacity to carry the additional load. The costs (and the benefits of this) to beshared between the two feeders interconnected by the tie. A 44% improvement in SAIDIis achieved and the option has a PVR slightly above 1.0.

12.5.3 It is unlikely that a tie would be constructed without providing remote or better stillautomatic means of effecting the interconnection (which is normally required to be opento limit fault or circulating currents).

Remote Operation of Switches

12.5.4 This option proposes the installation of more ACR’s and remote or automatic switches toquickly remove a fault from the distribution feeder in a manner that affects the minimumnumber of customers possible. The costs assumed are $35,000 per ACR and $15,000per switch. In total $255,000 is proposed to be spent on the installation and correctcommissioning of these devices. The model predicts a 14% reduction in overall SAIDI(Table 12.2.2). Such schemes are well proven requiring only good design and training ofoperations staff to be successful.

12.5.5 Powercor’s own analysis of the fitting of ACR’s as a part of their price review submissionshows an even better return than indicated here reflecting the conservative approachtaken with the reliability modelling or Powercor’s optimism.


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12.5.6 Given the significant impact of providing this level of remote operation to parts of HVfeeders it is difficult to understand why Powercor is not taking all steps possible tocomplete the installation of remote controls to all zone substations.

12.5.7 Customer surveys have shown that they would in general prefer a reduction in thenumber of outages to a further reduction in the length of the outages. Other reliabilityimprovements considered here effect a greater reduction of the number of outagesoccurring.

Installation of Ties to Other Feeders and Remote Operation of Switches

12.5.8 Combinations of these two could be used to enhance the reliability still further. Option 5considers this and indicates a 74% improvement in SAIDI is achievable. Furtheroptimisation of the location of the ACR’s and switches given the availability of theinterconnection ties would result in still greater improvements particularly in SAIFI than isindicated in Table 12.5.1.

Installation of Remote Operation of Switches and Reduced Repair Times

12.5.9 Combinations of these two could be used to enhance the reliability still further. Option 6considers this and indicates a 41% improvement in SAIDI.

Table 12.5.1 Summary of Potential Means to Improve Medium Term Reliability

Overall ImprovementCost of option PVR

SAIFI SAIDI

Option 1

Installation of ties to otherfeeders

$540,000 1.2 -3% 44%

Option 4

ACR’s and Remote controlof switches

$255,000 1.5 5% 14%

Option 5

Installation of ties with ACRand auto switches

$795,000 1.5 5% 74%

Option 6

Installation of ACR’s andauto switches in combinationwith reduced repair times

$255,000 plus$57,000 per

annum1.5 35% 41%

Average improvement $500,000 1.5 15% 43%

12.6 MEDIUM TERM IMPROVEMENT COSTS & TARGETS FOR LOW RELIABILITY FEEDERS

12.6.1 Table 12.6.1 shows the reliability performance of low reliability feeders relative to theaverage. If a limit were set of no feeder reliability being poorer than three times theaverage then, three urban, four short rural and eleven long rural feeders would requireimprovement work. In reality it is likely that a further 10% more will require work as theimprovement to the worst performing inevitably lowers the average. If the limit is to bebased on multiples of the average performance for each feeder type (which is robust,ensuring that the gap between worst and average performer is maintained) then; twentyfeeders would require attention if the multiple is three times or only eight if it is four times.


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12.6.2 It is not likely that a justification for narrowing the range to a multiple of two would besustainable. Setting a limit of four times the benchmark will have little effect on raisingthe standards of reliability (affecting only 10,000 customers), but setting a limit of threetimes would improve the service to 23,000 (5%) of Powercor’s customers. A multiple ofaround 2.1 would improve the service to 10% of Powercor’s customers and requireimprovements to 34 feeders.

Table 12.6.1 Feeder Performance Relative to Average Feeder

Feeder TypeTotal numberof feeders

No of feeders >2x Average SAIDI



Urban 113 4 3 3

Short rural 92 11 4 1

Long rural 87 22 11 4

Total74 292 37 18 7

12.6.3 Table 12.6.2 demonstrates that the total cost is not excessive if a limit for the poorestperforming feeder of not to exceed 2.1 times the average is implemented. The costsutilised are from the results of the reliability performance model as summarised in Table12.5.1 together with the analysis above on the total number of feeders requiringimprovements with varying levels of limits that could be set.

Table 12.6.2 Cost of Implementing Feeder Reliability Limits

Limit Setat 2 xAverage

Limit Setat 2.1 xAverage



Average Improvement43% improvement to reliability

Average Cost$500,000

Contingency Factor75 1.4 1.3 1.2 1.1

Total Cost per Feeder$700,000 $650,000 $600,000 $550,000

Number of Feeders to Improve37 34 20 8

Total Cost$25.9m $22.1m $12m $4.4m

12.6.4 The impact on the whole Powercor distribution network is for a reduction in SAIDI of 11%if this work is focussed entirely on low reliability feeders (more than 2.1 times poorer thanthe average) even if the average improvement was 35%, not the 43% determined by themodel.

12.6.5 Powercor’s enhanced Reliability Case submission to the Office during the ElectricityPrice Determination indicated that Powercor required $31m to achieve a 14% overallimprovement in SAIDI, which equates to a cost of $24.5m to achieve an 11%improvement. This is slightly in excess of the $22.1m determined by this reliabilitymodel.

74 Excluded are feeders with incomplete data or known exceptions75 The contingency factor takes account of the possibility that the modelled feeder BAN008 is not typical and

the likelihood of this increases as the number of feeder to be improved increases.


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12.7 LONG TERM IMPROVEMENTS TO LOW RELIABILITY FEEDERS.

12.7.1 The limiting factor on significant long-term improvement to low reliability feeders is thewillingness of consumers to pay additional amounts for the delivery of electricity as theimprovements will require additional capital for reconstructing and reconfiguring thenetwork. A comprehensive survey of customer requirements and their preparedness topay is required before any recommendations can be made as to the level of reliabilitythat should be achieved.


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13 CONCLUSIONS

13.1 SIGNIFICANCE OF THE ISSUE OF LOW RELIABILITY FEEDERS

13.1.1 Powercor customers are affected more by outages associated with the distributionnetwork owned and operated by Powercor, than outages in the transmission orgeneration systems. The greatest impact (eighty five percent) is from incidents on thehigh voltage distribution feeders. The subtransmission system accounts for thirteenpercent and the low voltage reticulation to individual customers only around one percentof the total minutes off supply encountered by Powercor customers.

13.1.2 Customers reliability expectations and the network capability are potentially mismatched.Anecdotally, customers are indicating that they require higher levels of reliability than thenetwork was designed for when it was installed several decades ago. Satisfyingincreasing customer expectations requires a balance of short-term improvements inmaintenance practices or increased maintenance expenditure and longer term capitalexpenditure on reconfiguration of the network.

13.1.3 A six-percent improvement in the overall System Average Interruption Duration Indexover the period 1997 to 1999 is a relatively small change. Some indications show this tobe a part of an overall trend of improving performance, others that overall performance isneither improving nor deteriorating. The number of customers receiving low reliability(eleven percent) is not changing significantly (a small deterioration is apparent for verylow reliability feeders). Similarly the magnitude of the low reliability remains unchanged.This is despite the fact that Powercor has addressed some of the issues on low reliabilityfeeders. Clearly others have replaced them.

13.1.4 The fault rate has deteriorated by about five percent per year over the three year periodinvestigated. The fault rate is the number of sustained faults that occur per 100km of HVfeeder. It is a good indication of the reliability of the installed network as the measure isunaffected by the length of the feeder and largely insulated from the effects of thenumber of customers on the feeder. It is a reflection of the standard of construction andmaintenance and the suitability of the feeder design for the environment it is operating in.The impact of this deterioration on the outage statistics is being masked by means thatreduce the number of customers affected by outages such as the installation of ACR’s.

13.1.5 The ability to recognise how many times outages have occurred for a customer wouldyield a useful insight into the service being provided. Powercor reliability initiatives andapproach to analysis of the outage data takes no account of the service being providedto individual customers. Analysis of the reliability provided to individual customers islikely to show that some customers on a feeder receive a level of reliability three timespoorer than the average for the feeder. This range is superimposed on the variationsbetween feeders resulting in some customers receiving a level of reliability more than tentimes poorer than the average. Powercor could implement the functionality in the OMSsystem that analyses the number of outages suffered by individual customers.

13.2 LIMITATIONS OF THE DATA, INVESTIGATION METHODOLOGY AND FINDINGS

13.2.1 This investigation developed an understanding of the underlying causes of theinterruptions to supply by examining all interruptions to a valid selection of good andpoorly performing feeders of each type. The data in the outage information system usedto analyse network performance, including fault causes, has many inaccuracies but issufficiently accurate for the purposes of this investigation. Data that is more recent ismuch more accurate with the limitations having been addressed with a new computersystem introduced in December 1999. Powercor still need to improve the amount ofinformation captured, particularly in relation to the causes of outages recorded in theOutage Management System (OMS).


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13.2.2 Problems with the Powercor outage management system prevented the use of currentdata when selecting the appropriate feeders for analysis. The data collected byPowercor on outages is incomplete with 1997 data in particular being of a low accuracy.The outage category “Unknown” is used extensively. This and other inaccuracies andlimitations arising from the data although in some cases significant are not considered tohave had a major effect on the findings. Given the quantity of data the error rate is lowand is not expected to have a particular bias to it. The quantity of data and thecrosschecking of it with data already supplied to the Office confirmed that the data wasthe best available and removed any likely sampling errors.

13.2.3 The comprehensive methodology developed resulted in the selected feeders beingrepresentative of the network. Selection based on detailed modelling and analysis of allfeeder types, performance, performance trends and other influencing factors wasundertaken on a rigorous and repeatable basis. Consequently, the selected feederscover all the potentially contingent factors on supply reliability. Detailed analysis ofselected feeders is still considered more appropriate than a high level audit.

13.2.4 The methodology utilised is also not considered to have had a significant effect on thefindings. Future investigations of Powercor could be conducted in a more-timely mannerwith the development of the requirements of the Office from this investigation beingmade available to any future investigation. Future investigations by utilising the betteroutage data that will be available then could focus more readily on the key issues beforeconcentrating on the investigation of a smaller number of feeders or concentrate on partsof feeders with particular causes of outages.

13.3 PRINCIPAL CAUSES OF OUTAGES OVER THE LAST THREE YEARS

13.3.1 Faults on the sub transmission system caused thirteen percent of all customer minutesoff supply, the causes of these faults were as varied and extensive as the causes on theHV distribution system. The effect of the outages could largely be eliminated if the subtransmission system was extended to include duplication of supplies to all zonesubstations, the security of supply standard currently in use does not require this. Theviability of this should be evaluated in conjunction with ascertaining both the customerswillingness to pay for a long-term improvement in reliability and the need foraugmentation to meet capacity requirements.

13.3.2 One cause accounts for over 50% of the total CMOS for many of the feedersinvestigated. Elimination of this cause would be very effective if it could be achieved.

13.3.3 Lightning causes twenty-two percent of all outages and thirty three percent of allcustomer minutes off supply on long rural feeders, eleven percent of customer minutesfor the whole Powercor network. Lightning tends to affect specific areas and iswidespread across those areas. Often multiple coincident feeder outages occur whichtends to extend the duration of the faults given the limited number of Powercor staffavailable to effect repair and restoration. Lightning is the initiator of an outage, butinadequate lightning protection measures lead to equipment failure, which then causesthe outage or a subsequent outage when the network is next subjected to stress. Thereare a number of locations seen where an improvement in the way lightning arrestors arefitted could have reduced the effect of lightning. A large proportion of the CMOSattributed to lightning results from damage to distribution substations. Powercor’sphilosophy of not fitting lightning arrestors to transformers of less than 25kVA is commonpractice but does result in damage to small transformers from lightning.

13.3.4 Planned outages accounted for 20% of all customer minutes off supply in 1999 and 16%over the whole period investigated. While the total impact of planned outages is nowless than earlier years, it is still 30% greater than TXU. Powercor could, with someinnovation, reduce its planned SAIDI without limiting the level of maintenance andreliability improvement work it undertakes through the extension of live line maintenancework. The utilisation of small generators to provide a supply during off load maintenanceand the installation of additional interconnections between feeders would also help


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13.3.5 Malfunction and electrical overload account for more than fifty percent of the number ofoutages on urban and short rural feeders and nearly forty percent on long rural feeders.In total these amount to seventeen percent of all customer minutes off supply. Bothmalfunction and electrical overload are equipment age or system operation relatedproblems. Additional expenditure on maintenance would reduce the number of outagesbeing initiated by these controllable causes.

13.3.6 Faults caused by birds, animals and trees also contributed to the total number ofcustomer minutes off supply. Preventing access by animals to the HV structures andremoving the possibility of birds causing a flashover between the conductors, or aconductor and part of the support structure by insulating parts of the network can to anextent be effective in eliminating these outages.

13.3.7 There is no overall improvement in the duration of faults over the period considered inthis investigation. The duration of faults in urban areas is reducing whilst in rural areas itis increasing by a small amount.

13.4 REASONS FOR LOW RELIABILITY

Asset Management

13.4.1 Powercor would benefit from the utilisation of an Asset Management Plan. The planwould effectively communicate and link corporate goals to asset management activitiesand provide a framework for reviewing the effectiveness of asset management. Similarlythe Powercor risk management strategies are incomplete and Powercor are unable todemonstrate they had appropriate risk management strategies for their networkbusiness. Adoption of scenario planning could result in more robust asset managementtogether with ensuring an appropriate risk management regime is in place.

13.4.2 Effective communication across the Powercor process organisation is essential. With theprocess leaders and teams dispersed across the various depots effective communicationis more difficult and more necessary.

13.4.3 Powercor maintenance practices are sub optimal. Reliability Centred Maintenance(RCM) has been adopted in principle, only the condition-based component has beenimplemented. The “reliability” functionality is only now being considered and utilised asPowercor move to more location dependent maintenance routines in specific locations.

13.4.4 All the benefits are not being obtained from major IT investment. Powercor haveextensive and recently installed IT systems, with business rules locked in. The fullbenefits of these investments have yet to be realised. The business is informationtechnology driven, however, it would appear that some improvements could be achievedwith lower costs in a less technology intensive way than is currently being considered byPowercor. A greater degree of analysis of the benefits to be achieved should beconsidered.

13.4.5 Key documents are still in draft form such as the procedure for identifying defects andrepair requirements, Asset Inspection Work Practice and on-line process information.These should be completed and implemented. The process driven nature of thebusiness model adopted by Powercor relies heavily on all parts of the business workingto the same process in a consistent manner. Without the completion of thedocumentation that describes the processes the likelihood of achieving this is muchlower.

13.4.6 Powercor would benefit from developing strategies to ensure that local knowledge isfactored into decision-making processes. There are functional centres of excellence butfunctional process teams are often not fully aware of local factors that influence thereliability of individual feeders.


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Design and Construction

13.4.7 Powercor current design and construction practices and the existing network constructionis sound and based on well-proven engineering principles with just a few exceptions.There are a variety of pole top designs in use. The new pole top design should improvereliability but post insulators should be used instead of pin insulators. Transformer andother HV structure pole design are complex. These poles are comparatively clutteredwith phase to phase and phase to earth clearances much smaller than normal lineclearance. Reliability improvements could be achieved through improvements to each ofthese as well as attention to the design and implementation of fusing and protection asdetailed in section 13.5.

13.4.8 Feeder Planning could be improved. No one function or person “owns” the feederreliability, hence reliability improvements are often given a lower priority than capacityrequirements which then becomes the driver for enhancements to the feeders. ThePowercor process structure relies on senior management interaction to ensure that bothcapacity and reliability issues are considered during major work on the feeder.

Maintenance Practices

13.4.9 Powercor use an independent contractor for maintenance inspection of feeders but thenuse their own staff to re-inspect 10% of the work, this is a high re-inspection rate giventhe routine nature of the inspections. If a maintenance requirement is identified the siteis often visited again leading to some work sites being visited three times.

13.4.10 Powercor have stated that the inspection of surf coast feeder DDL023 (location of arecent spate of pole top fires) presently in hand is the first time the feeder has beenchecked effectively. This is a concern and brings into question the effectiveness ofinspections of the rest of the network that appeared to be good, although some variationsin standards were apparent during the feeder inspections.

13.4.11 Vegetation management could be improved. Outages due to vegetation are notreducing. The inability to get vegetation trimmed in a timely manner by local Shires innon-bush fire areas is likely to be impacting on supply reliability. This is difficult toresolve as the responsibility for the work lies with the Shires but the effect of not carryingit out impacts on Powercor (and the other Distribution Businesses).

Maintenance Expenditure

13.4.12 Expenditure per customer is increasing and there is no clear indication of Powercorreducing expenditure significantly over the past three years aside from the levels thatcould be associated with efficiency gains through better work practices. The plannedrate of increase is greater for customers connected to long rural feeders than forcustomers connected to an urban or short rural feeder. Furthermore Powercor iscurrently spending over twice as much per customer on long rural feeders than it is onshort rural and urban feeders.

Operational Practices

13.4.13 At the end of 1999, only 40% of Powercor zone substations had remote control offeeders, this inhibits feeder reliability and inevitably increases the supply restoration time.An overall improvement in customer minutes off supply would be apparent if Powercorcompleted the installation of the SCADA system to all zone substations.

13.4.14 Powercor fault restoration process could be improved. Restoration following faults maybe being delayed by operators choosing to patrol a feeder following a fault instead oftrying a reclose. Greater and more consistent adherence to the OCEI guidelines onfeeder restoration following a fault would result in a reduction in outage duration in somecases. The preparation and utilisation of restoration plans would assist in outagecoordination and would reduce the duration of outages in some instances.


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13.4.15 Management of customers during faults could be improved. Powercor receive about 1million calls per year (fault and non-fault) which appears to be high. Customers reportinga fault are required to listen to two messages before speaking to an operator.

13.5 PREVENTION AND AVOIDANCE OF THE OUTAGES

13.5.1 There is no integrated reliability plan. Powercor have developed a number of initiativesfor improving reliability but there is no integrated plan covering both Network Planningand Network Performance processes to ensure that the optimum solutions are obtained.

13.5.2 Feeders do not have a regional sponsor. Powercor’s process structure has the potentialfor business efficiencies but requires good communications. There are functional centresof excellence but there is no regional presence with a comprehensive view of a feeder.

13.5.3 Feeder protection design has inadequacies. Powercor needs to review feeder fuse, andassociated fault ratings to ensure that appropriate protection operation and optimumreliability is being achieved.

13.5.4 The asset performance measures used to run the business are limited. Powercor useonly a few of the extensive range of Key Performance Indicators they have defined.Those that are used provide an incomplete picture of the effectiveness of assetmanagement.

13.5.5 Customer satisfaction monitoring is not effective. Customer satisfaction is monitored withindependent surveys, which are not monitored on a feeder or area basis. Powercor relyon customer complaints and media enquires for localised feedback. The Company isaware that they need to improve their customer communications and move away fromthe present reactive approach.

13.5.6 A greater use of live line working techniques and the utilisation of portable generatorswould have reduced planned outages by a significant amount

13.6 PERFORMANCE IMPROVEMENT OF LOW RELIABILITY FEEDERS

13.6.1 Powercor in some cases appears to be slow to eliminate the major causes of outages asthe same cause is a major contributor to CMOS for consecutive years on the samefeeder.

13.6.2 Development of a more structured approach to monitoring performance and expenditureat a feeder level, so as to ensure that performance improvement programs are costeffective and achieve planned outcomes could be undertaken by Powercor.

13.6.3 Powercor need an integrated strategy for improving reliability. Powercor have a numberof good initiatives for improving reliability (the focus is on the frequency of outages andshould include means to reduce the duration of outages) but need an integrated strategyto know best what to do where. The reliability strategies utilised are not based on soundanalysis.

13.6.4 Reliability improvement strategies and plans should be based on analysis of feederperformance with better data collection and verification processes. The causes ofoutages are not recorded in a standardised way. Improved data capture and access tomore extensive data by adopting a state or nation wide scheme such as National Faultand Interruption Reporting Scheme76 with agreed definitions and standards would assistthe Office and the DBs to understand the system performance better. This would yield

76 Instructions for Reporting to the National Fault and Interruption Reporting Scheme - Engineering Publications

July 1990


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benefits for the Distribution Businesses (knowing better the areas where attention toimprove reliability should be directed), for the Office and ultimately for the customer.

13.6.5 Reliability improvement strategies undertaken by Powercor do not appear to beachieving desired goals at a feeder level. Powercor need to take a more structuredapproach to monitoring performance and expenditure in order to ensure thatperformance improvement programs achieve the maximum cost benefits. Analysisshows a weak correlation between expenditure and performance improvement.

13.6.6 There are some benefits from introducing more open access (web based) to informationon supply reliability performance. The identification of where this would add value, theextent of the information that should be provided, the timing of information availabilityand mechanisms to be used to make the information available need to be investigated.

13.6.7 The model used for reliability analysis is rudimentary and considers only one year’s dataat a time ignoring the important consideration of trends in performance. The model ranksthe reliability improvement initiatives but fails to consider the differences in the costs perminute reduction in customer minutes off supply.

13.6.8 Powercor are implementing demand side management to reduce the need for feederenhancements. This could also defer capital expenditure to a greater extent thanrecognised in Powercor’s pricing submission and marginally improve reliability byreducing peak demands and thereby reducing the number of “electrical overload”outages.

13.6.9 The initiatives proposed by Powercor in the supplementary pricing submission lack thesame degree of rigour as the original submission.

13.7 EFFECT OF THE REGULATORY REGIME

13.7.1 Powercor responds to regulatory messages and its prioritisation of capital investment isheavily influenced by the need to cut costs and improve performance to customers onaverage. The publication of the 20 worst performing feeders has had an effect onPowercor’s response to worst served customers but the regulatory message is relativelyweak and there has been no overall change in the reliability of service to customers onlow reliability feeders. The shortcomings of the Electricity Distribution Code in terms of itaddressing average not specific performance are well known and need to be addressed.

13.7.2 The proposed incentives to improve performance for the worst served customers in thedraft price control decision will bring a sharper focus on the reliability of supply providedto customers. The current reporting requirements focus on feeder performance andwithin each feeder there is a range of performances being suffered by customers. Areporting regime based on worst served customers not feeders is technically feasible butwill require a significant increase in data handling capability of the Office of the RegulatorGeneral.

13.7.3 Additional reporting on outages including the cause to a common classification would bebeneficial and permit routine comparisons by the Office of the distribution business’s notjust on the basis of the number and duration of outages but on the causes andunderlying trends.

13.7.4 This investigation has potentially resulted in a more rigorous approach to reliabilityimprovement, particularly for customers on poorly performing feeders. The investigationcould be repeated in one to two years’ time both as a review of the effectiveness ofPowercor reliability improvements and to identify new factors impacting on the reliabilityof supply.


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13.8 CONCLUSIONS ON RELIABILITY TARGETS

13.8.1 The introduction of additional standards or changes to the Distribution Coderequirements should not be introduced until reliability incentive and guaranteed paymentinitiatives proposed in the Draft Decision have been implemented for a period and theireffectiveness evaluated.

13.8.2 Any revision to the Distribution Code should include a provision to ensure that no feederhas a level of reliability more than 2.1 times worse than the average for that type offeeder. This would improve the reliability of supply to 10% of customers.

13.8.3 Reporting on the basis of the reliability of supply to individual customers should beimplemented. Some customers on feeders currently receive a level of reliability morethan three times worse than the reported feeder average reliability. Conversely somereceive a level of reliability significantly better than average. The systems and processesto implement reporting on a single customer basis are achievable and not excessivelycostly.

13.8.4 At a cost of less than $100,000 per feeder a short-term reliability improvement forselected low reliability feeders could be achieved through increased maintenance.

13.8.5 Low reliability feeders could be improved In the medium term (one to three years) to thepoint where the number of outages and minutes off supply for the average customer isno more than 2.1 times greater than that encountered by the average customer on theaverage feeder. This would cost $22.1m and improve the reliability of supply to 10% ofPowercor customers.

13.8.6 A consensus on the long-term limits on reliability should be achieved with the customersof Powercor. The reliability analysis undertaken during this investigation is sound onlyfor reductions in the number of outages of around 50%. Long term, Powercor customersmay require, and be prepared to pay for greater levels of improvement. Work should beundertaken both to assess the customers willingness to pay and the costs of achievingmajor improvements in reliability. That the Powercor network can achieve good levels ofreliability is not in doubt.


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14 RECOMMENDATIONS

Our recommendations arising from this investigation relate to Powercor and the Office ofthe Regulator General.

14.1 POWERCOR

Management

14.1.1 Powercor should review their Key Performance Indicators (KPIs) and how these are usedto ensure that the business is effectively being managed. Powercor have defined anextensive range of KPIs in their Asset Management Strategy but are using only a few ofthese.

14.1.2 Powercor should ensure more effective communication in their process organisation.Process leaders and teams are dispersed across the various Powercor depots and thismakes effective communication more difficult.

14.1.3 Powercor should develop strategies to ensure that local knowledge is factored intodecision-making processes. There are functional centres of excellence but functionalprocess teams are often not fully aware of local factors that influence the reliability ofindividual feeders.

14.1.4 Powercor should review major IT systems to ensure that appropriate benefits areobtained. Powercor have extensive and recently installed IT systems with business ruleslocked in. The full benefits of these investments have yet to be realised. The business isinformation technology driven but there appears to be insufficient evaluation of businessneeds in the specification and implementation of IT solutions.

14.1.5 Powercor should prepare an integrated Asset Management Plan that covers assetmanagement systems and information; provides a comprehensive overview of theassets, their location and condition; gives service levels, security and availabilityperformance targets; discusses network development and life cycle asset managementplans; includes risk management criteria and evaluates performance against the plan(physical and financial). This plan should be updated at least annually.

Powercor have indicated that they are not in agreement with this requirement and have submitted“Powercor would strongly oppose any move to require the business to do this. The arrangementsthe Office currently has in place including the regulatory audits are sufficient to ensureregulatory compliance. This additional requirement would represent a further step towards moreintrusive form of economic regulation.”

14.1.6 Powercor should evaluate the underlying causes and the justification for the currentexpenditure on urban and short rural feeders which is presently many times that for longrural feeders when normalised on a per km basis.

Reliability Improvement

14.1.7 Powercor should improve information capture, particularly in relation to the causes ofoutages recorded in their Outage Management System (OMS).

14.1.8 Powercor should develop an integrated reliability improvement methodology to knowwhat work undertaken where will give the best improvement. Powercor has a number ofgood initiatives but no coordinated plan. The methodology would also include moreeffective reliability modelling and better economic analysis to consider performance andachieve more optimal economic reliability improvements.


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14.1.9 Powercor should base reliability improvement strategies and plans on sound feederperformance information and analysis, with a sound data collection process. Currentperformance recording is insufficiently accurate to be used as the basis for thedevelopment of reliability improvement plans.

14.1.10 Powercor should improve the integration of reliability considerations into feeder planningand more appropriately recognise such considerations in zone substation and feederplanning.

14.1.11 Powercor should develop a more structured approach to monitoring performance andexpenditure at a feeder level, so as to ensure that performance improvement programsachieve are cost effective and achieve planned outcomes.

14.1.12 Powercor should develop and implement plans to reduce the duration of outages.

14.1.13 Powercor should prepare restoration plans for troublesome feeders to assist in outagecoordination.

Maintenance Practices

14.1.14 Powercor should review their inspection practices. Powercor use an independentcontractor for maintenance inspection of feeders but then, in an inefficient manner, usetheir own staff to re-inspect 10% of this work, leading to 10% of the poles being visitedup to three times as part of the maintenance cycle. This rate of re-inspection appears tobe high.

14.1.15 Powercor should develop strategies to improve vegetation management in urban areas.Outages due to vegetation are not reducing. The inability to get vegetation trimmed in atimely manner by local Shires in non-bush fire areas is likely to be impacting on supplyreliability.

14.1.16 Powercor should improve maintenance practices by implementing Reliability CentredMaintenance (RCM) more fully. Although Reliability Centred Maintenance (RCM) hasbeen adopted in principle, only the condition-based component has been implementedwith “reliability” functionality yet to be adopted to any extent. Use of full RCM will ensurethat the maintenance effort is more effective.

Planning and Construction

14.1.17 Powercor should use line post insulators, instead of pin insulators, in the new pole topdesign, if, as is understood to be the case, the line post insulator is of a similar price.Line post insulators are less prone to pin hole failure and cracking as a result ofcorrosion of the pin where it screws into the porcelain.

14.1.18 Powercor should review the design of transformer and recloser pole structures. Thesepoles are comparatively cluttered with unnecessary components, resulting in reducedreliability because of phase to phase and phase to earth clearances being much smallerthan normal line clearance.

14.1.19 Powercor should review feeder fuse and associated fault ratings to ensure appropriateprotection operation and that optimum reliability is being achieved.

14.1.20 Powercor should accelerate the implementation of remote control of all zone substations.At the end of 1999, only 40% of zone substations had remote control of feeders.

Customer Service

14.1.21 Powercor should develop more effective customer satisfaction monitoring so thatinformation is captured by feeder and possibly area. This would reduce the reliance oncustomer complaints and media enquiries for feedback would better focus Powercor’s


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reliability improvement work. This could also reduce the 1 million calls per year (fault andnon-fault) Powercor receives.

14.1.22 Powercor should improve communications with customers during faults. Customerswanting to report a fault during an incident have to listen to two messages lasting justover a minute in total before getting to an operator to provide information helpful inlocating a fault.

14.1.23 Powercor should install a system that can analyse the number of outages suffered byindividual customers. The ability to recognise from the outage data how many timesoutages have occurred for a customer would yield a useful insight into the service beingprovided.

14.2 THE OFFICE

14.2.1 The Office should review the Distribution Code77 reliability minimum standards as theyare based on average values for all rural and urban customers. Once the effectivenessof the measures adopted in the Draft Determination (Minimum Service Levels and the Sfactor tariff adjustment) have been evaluated caps should be adopted to specify worstreliability levels acceptable for each feeder category to ensure that no feeder has a levelof reliability more than an agreed number of times poorer that the average.

14.2.2 The adoption of a reporting regime based on worst served customers as well as poorlyperforming feeders should be considered further in association with the initiatives onGuaranteed Service Levels set out in the draft Electricity Price Determination.

14.2.3 The Office should require Distribution Businesses (DB’s) to produce annual AssetManagement Plans, including reliability improvement plans. These should collate theDB’s strategies and plans for managing the network assets and integrate the networkcapacity and reliability improvement initiatives. The Office should publicly disclose theseon the Internet and subject them to an audit process.

14.2.4 There are a number of recent international examples where major interruptions haveoccurred as a result of multiple faults. There are parts of the Powercor network wheresingle, or credible double faults will result in a loss of supply. The Office should considerthe validity of developing and introducing an appropriate security of supply standard forthe sub transmission network. For the HV network this is less critical but an audit and fullpublic disclosure of the DB's own risk assessment methods should be undertaken. Thiswould result in an informed customer view of the probable levels of security, and if a lowrisk was realised what actions would be taken to provide the required level of security.

14.2.5 The Office would benefit from a better understanding of the performance of all DB’sincluding the underlying causes of performance variations. The gathering, interpretationand publishing of outage data including the causes of outages should be undertaken andwill benefit customers of all the Distribution Businesses through a better understanding ofthe causes and the mitigation strategies undertaken by the DB’s.

14.2.6 The Office may wish to consider the extension of the outage-reporting scheme a stagefurther and introduce a scheme for the all Victorian DB’s. The UK have operated since1968 a National Fault and Interruption Reporting Scheme78 (NAFIRS) this gathers detailsof all outages including equipment failure, the causes, reasons and actions taken intoone central location for all the distribution companies. The distribution business derivevalue from this by being able to draw upon the experience of a broader asset base andthe Office and customers would benefit from the greater detail being available to acommon set of definitions.

77 Electricity Distribution Code April 199978 Instructions for Reporting to the National Fault and Interruption Reporting Scheme - Engineering Publications

July 1990


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14.2.7 The Office should undertake a review of Powercor’s feeder reliability and expenditure in12 months time as this investigation has shown there are important issues that Powercorneeds to address.

14.2.8 The Office should review Powercor’s supplementary pricing submission79 for reliabilityimprovement as the initiatives lack quantification compared to the original submission.

14.2.9 The Office should carry out an economic review of the benefits of introducing more openaccess to information on supply reliability performance. This review should consider theextent of the information that should be provided, timing of information availability andmechanisms to be used to make the information available.

79 Document P95 Supplementary submission to the Regulator General - 2001 Electricity Distribution Price

Review 20 April 2000


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Appendix A. BRIEF RESUMES OF PB POWER STAFF UTILISED IN THIS INVESTIGATION


Doc No.71321 19/09/00 Page A 139

Robert Mann

Robert Mann as the Christchurch Engineering Manager of PB Power contributes to thecompany power generation and distribution engineering services. Robert Mann was theproject manager for this investigation.

Building on a strong background in power generation systems within England andZimbabwe Robert Mann developed skills in business and project development inIndochina, Singapore and Thailand. More recently, he was actively involved in thetechnical and operational management of a distribution company in New Zealand.

Robert Mann’s 21-year employment in the electricity industry includes experience in plantoperations, maintenance and management in a large government owned utility, and thena privatised utility. Robert has also gained experience in strategic market and businessdevelopment, project evaluation and management in a new business sector and morerecently project development and engineering management in a consumer owneddistribution business. Robert Mann has a focus on operational engineering founded onhis experience in a variety of management cultures and climates. Robert Mann’scompletion of a Diploma in Business Administration in 1992 has supported his BSc inElectrical Engineering and his technical skills with a sound managerial capability.

Bob Simpson

Bob Simpson utilised his 27-year’s electricity industry experience when contributing tothis investigation. In particular Bob Simpson utilised his knowledge of business processand system reviews; business system evaluation and implementation; business plandevelopment, monitoring, reporting and reviewing; development and monitoring of AssetManagement Plans and project management; business valuation.

Bob Simpson has an ME(Electrical) and is a Chartered Engineer, he has previouslyundertaken assignments examining performance targets and operational expenditure ofan Australian transmission company on behalf of ACCC; reviewing the outsourcingarrangements of a major Australian electricity network company; carrying out a duediligence of Australian Distribution company; acting as an independent investigator forNZ Electricity Market Surveillance Committee; monitoring a major NZ DistributionCompany contract award process for outsourcing maintenance; producing AssetManagement Plans for an electricity network company; the business valuation oftransmission company; developing Key Performance Indicators and targets for a largegeneration and transmission company and investigating a range of loss of supplyincidents.

John Tebbs

John Tebbs is a Chartered Engineer and Fellow of the Institution of Electrical Engineersand has worked for 35 years in the electricity distribution in the UK. He has operationaland senior manager experience in construction, network planning and operations andmanagement of a large distribution business supplying 2.3 million customers. Beforebecoming an independent consultant he was Network Strategy Director with a UKRegional Electricity Company with responsibility for network and equipment design andthe capital investment programme associated asset replacement and improvement inquality of supply in line with commitments to the regulator. Prior to that he wasresponsible for the 132 kV network and control centres and responsible for telecoms,SCADA and troublecall systems.

As a consultant he has been retained for work on the distribution price control review forGreat Britain and for Ireland and has worked with consultants advising the South AfricanGovernment on restructuring of the Electricity Distribution Industry. He takes a keeninterest in reliability of supply issues and has recently been involved in a review of theUK distribution company’s measurement systems associated with quality of supply, inadvance of the implementation of network performance incentives by the UK ElectricityRegulator, Ofgem.


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Geoff Brown

Geoff Brown has 28 years experience in the distribution industry, with electricalengineering experience covering high voltage transmission systems, and medium andlow voltage distribution systems. Geoff Brown has had considerable international designexperience of electrical systems and has been responsible for a review of the assetvaluation of 330 kV and 132 kV transmission systems and a Regulatory Technical Auditin Victoria. Geoff Brown was also the Team Leader for a review of the optimisation rulesfor regulatory asset valuations.

Geoff Brown has a BBS and an ME, Electrical. For this investigation Geoff’s experiencein, the condition assessment of distribution systems, design studies and the designreview of distribution systems, the design and installation of distribution and transmissionequipment were all utilised. Geoff Brown was previously employed by a New Zealanddistribution company and undertook the design of 11 kV and 400 kV overhead andunderground reticulation.

Gamani Ranasinghe

Gamini Ranasinghe is a senior consultant in the power systems section of PB Power,with a thorough understanding and a detailed knowledge of all technical aspects of thesubtransmission and distribution networks. Gamini Ranasinghe utilised his 20 yearsexperience as an electrical engineer in the electricity supply industry when contributing tothe distribution planning, optimisation and risk assessment included in this investigation.

Gamini Ranasinghe has a BSc(Eng) and a MEngSc in Electrical Power Engineering andis a Chartered Engineer with expertise including system planning, probabilistic systemplanning assessment techniques, system reliability modelling and analysis, loadforecasting, power system analysis, optimisation techniques, and subtransmission anddistribution system design. Gamini Ranasinghe is fully conversant with the financialaspects relating to the preparation of business cases, economic evaluations andeconomic feasibility studies for network projects in a competitive economic environment.

Steve Mutton

Steve Mutton has seventeen years experience in the power generation and distributionindustry and has been involved with many of New Zealand’s 220 kV, 110 kV, 33 kV and11 kV substations. Recently, Steve has been working with a large New Zealanddistribution company undertaking project management, design and contractmanagement roles in new and existing zone substation and feeder rearrangementprojects.

For this investigation Steve’s experience in the design and installation of distribution andtransmission equipment and the condition assessment of distribution systems were allutilised.

John Bradbury

Having been employed in the Electricity Supply Industry for 39 years John Bradbury hasa wide experience of all facets of the business, with particular knowledge and expertisein the management of large Distribution Businesses having been the Senior GeneralManager (Distribution) for a South African utility with sales of more than 180 TWh perannum. In addition, John Bradbury utilised his experience in distribution system designand operation for this investigation.

John Bradbury has a BSc Eng (Electrical) and has previously undertaken assignmentson distribution business performance improvement and restructuring; network tariffs andspecial pricing arrangements for industrial customers. John Bradbury has evaluatedinvestment opportunities and developed a Power Purchase Agreement for the purchaseof energy from a “Municipal / Private” Joint Venture generating entity and has beeninvolved in rural electrification programmes and collaborated with a national electricityregulator on pricing and structural issues.


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Appendix B. DETAILS OF FEEDER PERFORMANCE


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Unplanned CMOS Planned CMOS Unplanned SAIFI Planned SAIFIFeederID

Year Type Length(km)

Cust.No

MVA

Total Percust

% oftotal

Total Percust

% oftotal

Total Per100km

Total Per100km

AaratART023 1997 Short Rural 187 944 3 237,798 252 84.3% 44,196 47 15.7% 2.7 1.4 0.5 0.3ART031 1997 Short Rural 59 1,251 3 73,183 58 49.0% 76,094 61 51.0% 4.4 7.4 0.3 0.6ART033 1997 Long Rural 651 1,990 3 409,558 206 74.1% 143,205 72 25.9% 6.4 1.0 0.9 0.1ART034 1997 Short Rural 24 1,862 3 206,412 111 96.3% 7,860 4 3.7% 3.8 15.9 0.1 0.3AltonaAL002 1997 Urban 17 1,429 4 110,840 78 66.4% 56,065 39 33.6% 1.1 6.3 0.2 1.2AL006 1997 Urban 1 2 5 40 20 100.0 0 0 0.0% 0.5 50.0 0.0 0.0AL007 1997 Urban 15 1,273 5 48,487 38 85.2% 8,415 7 14.8% 0.3 2.1 0.0 0.1AL012 1997 Urban 14 3,130 7 607,375 194 83.4% 120,840 39 16.6% 1.2 8.9 0.1 0.7Bacchus MarshBMH003 1997 Long Rural 365 3,562 7 293,275 82 86.3% 46,625 13 13.7% 2.7 0.7 0.0 0.0BMH004 1997 Short Rural 44 2,891 6 266,240 92 97.0% 8,200 3 3.0% 2.4 5.4 0.0 0.1BMH005 1997 Short Rural 9 4 4 0 0 0 0 1.0 11.1 0.0 0.0BMH006 1997 Short Rural 130 960 4 164,592 171 86.0% 26,852 28 14.0% 3.6 2.8 0.1 0.1Ballarat NorthBAN001 1997 Long Rural 286 1,503 6 382,894 255 88.0% 52,398 35 12.0% 5.1 1.8 0.2 0.1BAN002 1997 Urban 15 2,372 10 638,763 269 95.7% 28,500 12 4.3% 7.8 52.0 0.1 0.7BAN003 1997 Urban 4 604 10 719 1 100.0 0 0 0.0% 0.0 0.5 0.0 0.0BAN004 1997 Urban 17 608 7 10,904 18 91.9% 960 2 8.1% 0.2 1.4 0.0 0.0BAN005 1997 Urban 11 1,494 4 4,214 3 96.9% 133 0 3.1% 0.0 0.4 0.0 0.0BAN006 1997 Urban 17 4,967 8 455,944 92 91.0% 45,267 9 9.0% 2.6 15.1 0.0 0.2BAN007 1997 Short Rural 75 3,668 11 390,624 106 98.4% 6,400 2 1.6% 2.3 3.0 0.0 0.0BAN008 1997 Long Rural 302 4,117 9 2,541,332 617 92.6% 202,815 49 7.4% 11.3 3.8 0.3 0.1BAN009 1997 Long Rural 259 2,541 8 793,192 312 94.2% 48,723 19 5.8% 5.4 2.1 0.2 0.1BAN011 1997 Short Rural 60 1,733 4 596,621 344 90.8% 60,281 35 9.2% 11.3 18.8 0.2 0.3BAN013 1997 Urban 7 500 8 1,396 3 94.6% 80 0 5.4% 0.0 0.5 0.0 0.1BAN015 1997 Short Rural 51 3,560 7 227,653 64 89.0% 28,271 8 11.0% 4.3 8.4 0.1 0.2Ballarat SouthBAS011 1997 Long Rural 602 3,075 9 1,006,207 327 77.7% 288,112 94 22.3% 9.5 1.6 0.7 0.1BAS012 1997 Urban 10 2,174 7 10,448 5 36.9% 17,888 8 63.1% 0.1 0.7 0.1 0.6BAS013 1997 Short Rural 35 2,029 7 88,331 44 42.0% 121,763 60 58.0% 1.1 3.1 0.2 0.7BAS014 1997 Short Rural 1 3,070 7 22,319 7 23.2% 74,075 24 76.8% 0.1 12.5 0.1 12.2BAS021 1997 Long Rural 362 3,697 9 702,264 190 94.0% 45,145 12 6.0% 4.7 1.3 0.1 0.0BAS022 1997 Long Rural 373 4,775 7 1,272,658 267 87.0% 189,868 40 13.0% 4.4 1.2 0.2 0.1BAS023 1997 Short Rural 30 2,922 6 25,101 9 41.7% 35,157 12 58.3% 1.1 3.7 0.1 0.3BAS024 1997 Urban 3 103 7 0 0 0.0% 255 2 100.0 0.0 0.3 0.0 1.0BAS034 1997 Urban 6 3,410 8 62,690 18 48.9% 65,490 19 51.1% 2.8 47.3 0.1 2.0BendigoBGO011 1997 Urban 1 568 9 9,688 17 28.9% 23,790 42 71.1% 0.4 41.4 0.1 11.3BGO012 1997 Short Rural 34 4,234 8 94,956 22 56.1% 74,292 18 43.9% 0.2 0.6 0.1 0.4BGO013 1997 Long Rural 240 4,164 10 331,503 80 16.5% 1,682,437 404 83.5% 1.8 0.8 1.1 0.5BGO021 1997 Urban 6 1,630 6 27,327 17 100.0 0 0 0.0% 0.1 2.4 0.0 0.0BGO022 1997 Short Rural 139 4,857 9 708,818 146 82.0% 155,632 32 18.0% 2.8 2.0 0.2 0.1BGO023 1997 Urban 2 597 7 31,798 53 30.7% 71,805 120 69.3% 0.5 26.0 0.1 4.6


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Cust.No

MVA

Total Percust

% oftotal

Total Percust

% oftotal

Total Per100km

Total Per100km

BendigoBET001 1997 Urban 8 2,680 6 47,970 18 68.5% 22,016 8 31.5% 1.3 16.2 0.1 0.8BET002 1997 Short Rural 31 2,657 6 154,576 58 88.1% 20,790 8 11.9% 1.2 4.0 0.1 0.2BET003 1997 Urban 7 308 5 1,482 5 3.9% 36,470 118 96.1% 0.0 0.6 1.3 18.1BET004 1997 Short Rural 50 2,132 5 238,595 112 97.3% 6,700 3 2.7% 1.2 2.3 0.1 0.3BrooklynBLT016 1997 Urban 10 89 8 7,253 81 64.7% 3,950 44 35.3% 1.2 12.5 0.1 1.2BLT017 1997 Urban 10 806 10 83,252 103 100.0 40 0 0.0% 4.4 44.3 0.0 0.0BLT020 1997 Urban 17 72 8 4,360 61 64.8% 2,370 33 35.2% 0.5 2.9 0.1 0.4BLT022 1997 Short Rural 21 1,620 4 740,712 457 100.0 0 0 0.0% 5.3 25.3 0.0 0.0BLT030 1997 Urban 17 1,855 6 220,982 119 100.0 0 0 0.0% 2.5 14.6 0.0 0.0BLT031 1997 Urban 18 1,185 5 10,599 9 70.6% 4,405 4 29.4% 0.1 0.3 0.0 0.1CamperdownCDN001 1997 Long Rural 284 1,742 8 1,026,992 590 98.8% 12,065 7 1.2% 7.7 2.7 0.2 0.1CDN002 1997 Short Rural 175 547 3 201,944 369 99.3% 1,466 3 0.7% 3.0 1.7 0.2 0.1CDN003 1997 Short Rural 18 1,547 3 29,438 19 100.0 0 0 0.0% 1.2 6.6 0.0 0.0CDN004 1997 Long Rural 285 817 3 270,436 331 88.0% 36,955 45 12.0% 3.3 1.2 0.3 0.1CDN006 1997 Long Rural 315 1,023 3 199,543 195 68.6% 91,137 89 31.4% 1.4 0.4 0.6 0.2CastlemaineCMN001 1997 Short Rural 100 1,396 2 25,324 18 13.4% 163,617 117 86.6% 1.2 1.2 0.4 0.4CMN002 1997 Long Rural 289 2,304 3 782,644 340 81.8% 173,775 75 18.2% 3.5 1.2 0.4 0.1CMN003 1997 Long Rural 202 2,416 6 149,061 62 98.8% 1,751 1 1.2% 0.9 0.4 0.0 0.0CMN004 1997 Short Rural 167 1,320 3 84,793 64 84.7% 15,290 12 15.3% 0.4 0.2 0.1 0.0CMN005 1997 Short Rural 20 939 6 40,523 43 99.7% 124 0 0.3% 0.5 2.7 0.0 0.0CharltonCTN001 1997 Long Rural 575 1,771 5 172,718 98 64.3% 95,798 54 35.7% 2.9 0.5 0.8 0.1CTN002 1997 Long Rural 368 1,183 3 165,052 140 92.5% 13,397 11 7.5% 3.6 1.0 0.3 0.1CTN003 1997 Long Rural 508 1,414 4 363,444 257 80.5% 88,009 62 19.5% 4.6 0.9 0.7 0.1CTN004 1997 Short Rural 180 1,174 4 99,962 85 92.6% 7,935 7 7.4% 2.9 1.6 0.1 0.1CTN005 1997 Urban 8 614 2 75,848 124 100.0 0 0 0.0% 3.3 41.1 0.0 0.0CTN006 1997 Long Rural 1541 2,363 6 47,547 20 22.6% 162,384 69 77.4% 2.1 0.1 0.9 0.1Cobram EastCME014 1997 Short Rural 134 2,057 5 1,866,555 907 99.7% 5,986 3 0.3% 8.7 6.5 0.0 0.0CME015 1997 Short Rural 163 584 8 489,843 839 99.8% 900 2 0.2% 6.8 4.2 0.0 0.0CME016 1997 Long Rural 298 1,700 6 1,476,861 869 95.8% 64,003 38 4.2% 9.0 3.0 0.2 0.1CME021 1997 Urban 1 1,897 9 1,165,359 614 99.2% 9,425 5 0.8% 2.5 251.3 0.1 6.8CME022 1997 Urban 4 390 5 376,236 965 96.0% 15,702 40 4.0% 10.0 249.9 0.2 6.0CohunaCHA003 1997 Short Rural 111 1,242 5 250,024 201 63.9% 141,345 114 36.1% 1.9 1.7 0.5 0.5CHA005 1997 Long Rural 499 1,212 6 218,707 180 99.6% 820 1 0.4% 2.0 0.4 0.0 0.0CHA006 1997 Long Rural 667 1,530 6 524,476 343 93.4% 37,182 24 6.6% 2.0 0.3 0.1 0.0ColacCLC001 1997 Short Rural 14 1,831 3 132,080 72 80.4% 32,222 18 19.6% 3.2 22.7 0.1 0.6CLC002 1997 Urban 14 2,336 6 124,316 53 84.2% 23,332 10 15.8% 3.1 21.9 0.0 0.2CLC003 1997 Long Rural 382 1,499 6 648,977 433 95.3% 31,714 21 4.7% 12.1 3.2 0.1 0.0CLC004 1997 Short Rural 193 1,244 5 326,100 262 57.2% 244,096 196 42.8% 4.3 2.2 0.8 0.4


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Cust.No

MVA

Total Percust

% oftotal

Total Percust

% oftotal

Total Per100km

Total Per100km

CLC005 1997 Short Rural 104 1,654 3 277,483 168 81.4% 63,524 38 18.6% 11.4 11.0 0.2 0.2CLC006 1997 Long Rural 408 2,022 5 1,357,869 672 79.3% 354,230 175 20.7% 7.8 1.9 0.7 0.2CLC008 1997 Long Rural 312 3,196 6 2,486,269 778 76.7% 756,331 237 23.3% 18.4 5.9 0.8 0.3CorioCRO013 1997 Short Rural 147 3,790 8 1,075,308 284 91.7% 96,895 26 8.3% 5.1 3.4 0.1 0.1CRO021 1997 Urban 9 648 4 24,707 38 81.5% 5,610 9 18.5% 0.4 4.4 0.0 0.3CRO022 1997 Urban 11 3,249 7 31,760 10 78.3% 8,820 3 21.7% 1.9 17.6 0.0 0.2CRO023 1997 Short Rural 4 249 1 13,709 55 11.7% 103,330 415 88.3% 0.2 5.0 0.8 19.8CRO032 1997 Urban 1 3 7 781 260 100.0 0 0 0.0% 1.0 100.0 0.0 0.0CRO033 1997 Urban 4 19 2 5,413 285 94.4% 320 17 5.6% 2.9 72.4 0.2 5.3CRO034 1997 Urban 17 1,306 6 197,431 151 99.9% 186 0 0.1% 2.3 13.8 0.0 0.0DrysdaleDDL011 1997 Urban 1 2,878 4 40,684 14 12.6% 282,226 98 87.4% 1.2 120.1 0.3 26.3DDL012 1997 Short Rural 70 3,306 6 82,213 25 23.2% 272,113 82 76.8% 4.3 6.2 0.4 0.6DDL013 1997 Short Rural 88 2,853 5 70,533 25 15.2% 392,432 138 84.8% 4.2 4.8 0.6 0.7DDL014 1997 Short Rural 24 2,572 8 301,950 117 95.2% 15,075 6 4.8% 2.2 9.2 0.0 0.1DDL022 1997 Short Rural 60 2,874 6 37,389 13 23.8% 120,012 42 76.2% 2.1 3.6 0.2 0.3DDL023 1997 Short Rural 84 3,447 8 171,966 50 20.5% 666,662 193 79.5% 6.6 7.9 0.6 0.7DDL024 1997 Short Rural 85 1,563 5 52,249 33 9.9% 475,776 304 90.1% 0.2 0.2 0.8 1.0EaglehawkEHK021 1997 Urban 9 396 7 3,228 8 24.8% 9,762 25 75.2% 0.1 1.1 0.1 1.4EHK022 1997 Long Rural 321 3,987 9 509,526 128 77.9% 144,176 36 22.1% 1.6 0.5 0.1 0.0EHK023 1997 Urban 4 625 7 940 2 3.4% 27,080 43 96.6% 0.0 0.5 0.3 6.7EHK024 1997 Long Rural 915 3,663 10 461,149 126 89.0% 56,771 15 11.0% 2.5 0.3 0.2 0.0EHK032 1997 Short Rural 61 2,444 5 247,507 101 93.4% 17,538 7 6.6% 1.2 2.0 0.1 0.2EHK033 1997 Urban 3 2,208 4 105,979 48 98.6% 1,470 1 1.4% 0.6 21.4 0.1 3.2EHK034 1997 Urban 2 1,017 7 24,654 24 100.0 0 0 0.0% 2.3 114.4 0.0 0.0EchucaECA001 1997 Urban 8 2,020 8 45,740 23 88.4% 6,000 3 11.6% 0.3 3.8 0.0 0.1ECA003 1997 Short Rural 45 2,365 9 1,051,954 445 96.0% 43,425 18 4.0% 6.6 14.7 0.1 0.2ECA005 1997 Long Rural 254 909 6 173,767 191 78.8% 46,668 51 21.2% 4.2 1.7 0.3 0.1ECA007 1997 Long Rural 371 1,079 10 369,253 342 100.0 0 0 0.0% 2.2 0.6 0.0 0.0ECA010 1997 Urban 6 1,747 7 108,815 62 52.2% 99,541 57 47.8% 1.9 31.1 0.2 2.8ECA012 1997 Long Rural 324 2,181 7 293,937 135 77.2% 86,793 40 22.8% 2.4 0.7 0.1 0.0Ford NorthFNS011 1997 Short Rural 105 2,673 8 181,591 68 72.4% 69,125 26 27.6% 1.5 1.5 0.1 0.1FNS012 1997 Short Rural 70 3,287 8 29,305 9 5.8% 472,990 144 94.2% 1.1 1.5 0.8 1.1FNS021 1997 Urban 1 808 4 13,045 16 20.8% 49,601 61 79.2% 2.2 216.1 0.3 30.8FNS022 1997 Short Rural 167 545 5 315,180 578 99.5% 1,437 3 0.5% 5.0 3.0 0.0 0.0FNS032 1997 Short Rural 16 267 4 119,933 449 81.6% 27,040 101 18.4% 5.6 34.7 0.4 2.8GeelongGL011 1997 Urban 15 1,467 4 147,466 101 78.3% 40,780 28 21.7% 1.1 7.2 0.1 0.5GL012 1997 Urban 6 1,124 4 53,577 48 86.0% 8,696 8 14.0% 0.3 4.7 0.0 0.6GL013 1997 Urban 10 2,451 3 13,357 5 73.4% 4,845 2 26.6% 1.0 10.2 0.0 0.1GL014 1997 Urban 19 3,045 6 78,819 26 48.2% 84,551 28 51.8% 1.4 7.2 0.2 1.0GL015 1997 Urban 3 306 2 119 0 100.0 0 0 0.0% 0.0 0.1 0.0 0.0


Doc No.71321 19/09/00 Page B 145



Cust.No

MVA

Total Percust

% oftotal

Total Percust

% oftotal

Total Per100km

Total Per100km

GL021 1997 Short Rural 32 5,496 9 514,714 94 65.0% 277,633 51 35.0% 5.4 16.8 0.2 0.5GL022 1997 Urban 19 3,394 5 111,703 33 99.9% 124 0 0.1% 0.3 1.5 0.0 0.0GL023 1997 Urban 6 1,002 3 11,202 11 96.8% 372 0 3.2% 0.3 4.6 0.0 0.1GL024 1997 Long Rural 398 4,007 7 1,330,725 332 88.3% 175,565 44 11.7% 5.7 1.4 0.2 0.0Geelong BGB011 1997 Urban 2 7 3 371 53 67.3% 180 26 32.7% 0.4 21.4 0.4 21.4GB012 1997 Urban 3 14 3 0 0 0.0% 2,340 167 100.0 0.0 0.0 0.2 7.1GB014 1997 Urban 3 454 7 40,473 89 79.5% 10,440 23 20.5% 1.5 48.5 0.1 2.2GB032 1997 Urban 2 3 5 0 0 0 0 0.0 0.0 0.3 16.7

Geelong CityGCY012 1997 Urban 3 414 9 13,118 32 63.3% 7,605 18 36.7% 1.8 58.9 0.1 3.1GCY013 1997 Urban 1 3,324 5 7,488 2 16.1% 38,909 12 83.9% 0.0 2.5 0.0 3.9GCY014 1997 Urban 1 3,326 8 431,508 130 100.0 0 0 0.0% 3.1 314.0 0.0 0.0GCY021 1997 Urban 1 274 4 0 0 0.0% 36,885 135 100.0 0.0 0.0 0.4 43.1GCY022 1997 Urban 1 408 6 6,473 16 14.9% 36,844 90 85.1% 0.2 17.4 0.2 19.9GCY023 1997 Urban 4 3,364 9 114,052 34 95.1% 5,893 2 4.9% 4.5 112.5 0.0 0.1GCY024 1997 Urban 7 1,071 5 13,367 12 100.0 0 0 0.0% 0.1 1.6 0.0 0.0Geelong EastGLE011 1997 Urban 16 338 8 3,804 11 8.7% 40,168 119 91.3% 0.1 0.8 0.5 3.3GLE012 1997 Urban 8 827 7 8,169 10 11.5% 62,935 76 88.5% 0.1 0.7 0.2 2.7GLE013 1997 Short Rural 59 3,881 7 361,299 93 53.5% 313,642 81 46.5% 0.9 1.5 0.2 0.3GLE021 1997 Short Rural 120 3,163 7 72,737 23 53.0% 64,410 20 47.0% 0.1 0.1 0.1 0.1GLE024 1997 Short Rural 35 1,996 7 152,587 76 61.1% 97,088 49 38.9% 6.8 19.4 0.3 0.7GLE031 1997 Urban 15 2,559 6 30,112 12 24.1% 94,832 37 75.9% 0.1 0.8 0.1 0.9GLE032 1997 Urban 7 1,746 4 2,648 2 5.4% 46,215 26 94.6% 0.0 0.2 0.2 2.2GLE033 1997 Urban 16 1,893 8 347,199 183 58.8% 243,737 129 41.2% 2.5 15.8 0.6 4.0HamiltonHTN001 1997 Long Rural 376 846 2 245,372 290 95.5% 11,628 14 4.5% 1.5 0.4 0.4 0.1HTN002 1997 Long Rural 595 2,591 4 498,436 192 73.8% 177,389 68 26.2% 4.5 0.8 0.9 0.1HTN003 1997 Long Rural 321 1,773 3 221,359 125 90.9% 22,210 13 9.1% 2.6 0.8 0.5 0.1HTN004 1997 Short Rural 34 3,092 5 499,934 162 85.6% 84,071 27 14.4% 1.9 5.6 0.2 0.6HTN005 1997 Urban 3 2,670 5 185,371 69 53.4% 162,088 61 46.6% 1.5 49.7 0.4 12.6HTN006 1997 Long Rural 963 2,482 5 195,570 79 79.9% 49,060 20 20.1% 1.1 0.1 0.4 0.0HorshamHSM001 1997 Long Rural 744 2,247 4 636,398 283 75.3% 208,707 93 24.7% 3.4 0.5 0.4 0.1HSM002 1997 Long Rural 1336 2,975 5 1,796,930 604 91.7% 162,638 55 8.3% 8.7 0.6 0.3 0.0HSM003 1997 Long Rural 305 1,454 3 277,945 191 83.8% 53,642 37 16.2% 4.4 1.4 0.2 0.1HSM004 1997 Long Rural 471 1,948 2 1,663,989 854 92.9% 127,985 66 7.1% 8.6 1.8 0.4 0.1HSM005 1997 Long Rural 268 1,577 4 78,110 50 46.9% 88,439 56 53.1% 1.4 0.5 0.2 0.1HSM006 1997 Short Rural 172 2,053 5 441,617 215 89.5% 51,560 25 10.5% 3.3 1.9 0.1 0.1HSM009 1997 Urban 20 2,359 6 39,583 17 9.6% 373,302 158 90.4% 0.3 1.5 0.4 2.2HSM010 1997 Short Rural 27 3,030 7 361,153 119 58.7% 254,195 84 41.3% 1.3 4.8 0.5 1.7KerangKGT002 1997 Short Rural 41 2,081 6 299,842 144 73.0% 110,748 53 27.0% 1.4 3.5 0.6 1.5KGT003 1997 Long Rural 308 1,255 4 384,567 306 93.9% 25,025 20 6.1% 5.8 1.9 0.1 0.0KGT004 1997 Long Rural 325 819 2 221,194 270 99.6% 863 1 0.4% 1.1 0.3 0.1 0.0


Doc No.71321 19/09/00 Page B 146



Cust.No

MVA

Total Percust

% oftotal

Total Percust

% oftotal

Total Per100km

Total Per100km

KoroitKRT012 1997 Long Rural 225 1,475 2 322,609 219 86.3% 51,030 35 13.7% 1.6 0.7 0.1 0.1KRT013 1997 Long Rural 232 3,043 6 194,833 64 50.7% 189,660 62 49.3% 3.3 1.4 0.3 0.1KRT021 1997 Long Rural 371 1,533 7 133,323 87 61.6% 83,165 54 38.4% 2.9 0.8 0.4 0.1KRT022 1997 Urban 11 66 4 2,378 36 28.6% 5,928 90 71.4% 0.8 7.6 0.2 1.8KyabramKYM001 1997 Short Rural 156 1,128 10 217,663 193 66.3% 110,811 98 33.7% 5.3 3.4 0.5 0.3KYM002 1997 Long Rural 304 1,639 10 203,294 124 88.6% 26,233 16 11.4% 6.9 2.3 0.1 0.0KYM003 1997 Long Rural 392 1,512 6 594,779 393 95.1% 30,718 20 4.9% 9.6 2.4 0.1 0.0KYM004 1997 Short Rural 195 1,265 6 234,444 185 86.5% 36,600 29 13.5% 6.0 3.1 0.1 0.1KYM005 1997 Urban 25 2,501 6 156,667 63 72.2% 60,211 24 27.8% 2.5 10.2 0.2 0.8KYM006 1997 Short Rural 85 420 8 56,120 134 91.0% 5,536 13 9.0% 4.7 5.5 0.1 0.1LavertonLV001 1997 Urban 19 2,504 8 184,744 74 74.4% 63,516 25 25.6% 3.6 18.9 0.1 0.5LV002 1997 Short Rural 83 193 10 59,997 311 93.8% 3,940 20 6.2% 6.5 7.9 0.1 0.1LV003 1997 Short Rural 73 19 7 8,778 462 100.0 0 0 0.0% 11.9 16.4 0.0 0.0LV004 1997 Urban 33 3,910 10 314,693 80 73.0% 116,249 30 27.0% 5.0 15.2 0.1 0.2LV005 1997 Urban 14 632 8 133,369 211 90.7% 13,755 22 9.3% 2.6 18.9 0.1 0.5LV006 1997 Urban 68 5,177 13 371,201 72 64.6% 203,658 39 35.4% 3.5 5.1 0.1 0.2LV007 1997 Urban 19 1,486 11 53,623 36 63.9% 30,320 20 36.1% 0.4 1.9 0.1 0.4LV008 1997 Short Rural 90 2,999 10 1,290,783 430 93.6% 87,920 29 6.4% 10.4 11.5 0.1 0.1LV009 1997 Urban 24 4,091 10 597,086 146 82.3% 128,748 31 17.7% 1.7 7.1 0.1 0.3MaryboroughMRO004 1997 Short Rural 16 1,969 4 757,585 385 99.7% 2,083 1 0.3% 4.3 26.6 0.0 0.2MRO005 1997 Long Rural 332 1,700 4 305,461 180 69.5% 134,272 79 30.5% 2.6 0.8 0.4 0.1MRO006 1997 Urban 4 621 3 30,234 49 100.0 0 0 0.0% 1.3 31.4 0.0 0.0MRO007 1997 Long Rural 277 1,630 4 521,197 320 72.1% 201,288 123 27.9% 3.0 1.1 0.9 0.3MRO008 1997 Short Rural 192 2,360 5 414,109 175 98.3% 7,226 3 1.7% 2.3 1.2 0.0 0.0MeltonMLN011 1997 Short Rural 78 5,206 10 1,302,093 250 87.5% 185,805 36 12.5% 5.1 6.6 0.1 0.1MLN012 1997 Short Rural 136 4,248 8 1,554,183 366 91.7% 141,502 33 8.3% 7.5 5.5 0.1 0.1MLN021 1997 Short Rural 92 991 4 414,480 418 92.2% 35,145 35 7.8% 7.9 8.6 0.2 0.2MLN024 1997 Urban 31 3,095 9 114,492 37 35.6% 207,213 67 64.4% 3.0 9.8 0.2 0.8MerbeinMBN012 1997 Short Rural 43 1,897 7 47,602 25 100.0 0 0 0.0% 0.2 0.4 0.0 0.0MBN013 1997 Short Rural 43 433 3 41,138 95 22.7% 139,879 323 77.3% 1.3 2.9 1.1 2.5MBN014 1997 Short Rural 93 684 4 57,241 84 25.5% 166,842 244 74.5% 0.9 1.0 0.7 0.7MBN021 1997 Short Rural 125 1,164 5 205,723 177 38.6% 327,878 282 61.4% 1.0 0.8 0.9 0.7MBN022 1997 Short Rural 57 659 4 34,690 53 44.9% 42,641 65 55.1% 0.6 1.1 0.2 0.4MilduraMDA022 1997 Urban 12 2,902 12 20,790 7 29.5% 49,670 17 70.5% 0.1 0.9 0.0 0.4MDA023 1997 Short Rural 103 1,847 7 235,397 127 53.1% 207,923 113 46.9% 1.0 1.0 0.4 0.4MDA024 1997 Urban 14 603 6 30,757 51 71.2% 12,450 21 28.8% 0.4 3.1 0.1 0.7MDA031 1997 Short Rural 29 1,170 7 47,095 40 53.9% 40,230 34 46.1% 1.6 5.4 0.1 0.3MDA032 1997 Short Rural 42 2,423 10 21,685 9 29.5% 51,780 21 70.5% 0.1 0.3 0.1 0.2MDA033 1997 Urban 1 2,295 10 94,192 41 89.4% 11,125 5 10.6% 3.3 334.6 0.0 1.1


Doc No.71321 19/09/00 Page B 147



Cust.No

MVA

Total Percust

% oftotal

Total Percust

% oftotal

Total Per100km

Total Per100km

MooroopnaMNA014 1997 Long Rural 286 1,848 9 294,990 160 57.9% 214,585 116 42.1% 5.3 1.9 0.4 0.2MNA021 1997 Short Rural 49 2,425 10 362,371 149 93.2% 26,570 11 6.8% 4.6 9.4 0.0 0.1MNA022 1997 Urban 6 491 5 3,283 7 41.9% 4,548 9 58.1% 2.1 35.2 0.1 1.2MNA024 1997 Urban 15 863 5 13,615 16 36.6% 23,633 27 63.4% 1.1 7.1 0.2 1.2MNA034 1997 Long Rural 354 1,800 8 211,820 118 81.0% 49,740 28 19.0% 3.7 1.0 0.2 0.0NhillNHL015 1997 Long Rural 656 1,781 3 842,540 473 87.4% 121,907 68 12.6% 10.6 1.6 0.4 0.1NHL016 1997 Short Rural 192 1,413 3 388,139 275 85.9% 63,893 45 14.1% 3.3 1.7 0.6 0.3NHL031 1997 Long Rural 687 1,442 3 310,702 215 77.9% 88,247 61 22.1% 8.8 1.3 0.3 0.0NurmukaNKA001 1997 Long Rural 217 1,090 4 278,218 255 91.5% 25,798 24 8.5% 2.1 1.0 0.1 0.1NKA002 1997 Long Rural 261 1,753 5 938,166 535 71.2% 380,035 217 28.8% 5.2 2.0 0.7 0.3NKA003 1997 Short Rural 107 455 5 28,802 63 94.0% 1,840 4 6.0% 1.0 0.9 0.0 0.0NKA004 1997 Short Rural 132 2,161 7 260,861 121 70.7% 108,321 50 29.3% 1.7 1.3 0.2 0.1NKA005 1997 Short Rural 165 786 4 249,641 318 95.9% 10,721 14 4.1% 4.8 2.9 0.1 0.1NKA006 1997 Long Rural 316 1,237 6 216,043 175 42.1% 297,693 241 57.9% 2.8 0.9 1.1 0.3OuyenOYN001 1997 Long Rural 661 1,052 2 361,411 344 31.5% 786,913 748 68.5% 10.2 1.5 4.4 0.7OYN003 1997 Long Rural 262 462 1 227,746 493 89.3% 27,280 59 10.7% 6.6 2.5 0.4 0.1OYN005 1997 Long Rural 576 1,573 3 413,176 263 85.0% 73,120 46 15.0% 9.1 1.6 0.5 0.1OYN007 1997 Urban 1 635 3 272,904 430 100.0 0 0 0.0% 6.4 636.5 0.0 0.0PortlandPLD001 1997 Long Rural 590 893 3 50,681 57 38.8% 80,050 90 61.2% 1.1 0.2 0.8 0.1PLD003 1997 Short Rural 30 2,015 5 1,236,927 614 91.4% 116,826 58 8.6% 7.2 23.9 1.9 6.4PLD004 1997 Short Rural 33 2,488 4 446,485 179 53.5% 388,829 156 46.5% 3.8 11.6 0.5 1.6PLD005 1997 Short Rural 11 159 3 85 1 9.1% 845 5 90.9% 0.0 0.2 0.5 4.2PLD006 1997 Short Rural 104 2,662 5 802,044 301 95.2% 40,854 15 4.8% 4.7 4.5 0.1 0.1Red CliffsRCT011 1997 Short Rural 46 619 2 40,789 66 71.7% 16,113 26 28.3% 0.7 1.6 0.2 0.5RCT013 1997 Long Rural 222 672 8 570,930 850 87.7% 80,385 120 12.3% 5.1 2.3 0.7 0.3RCT014 1997 Short Rural 165 825 11 233,977 284 72.6% 88,304 107 27.4% 2.6 1.5 0.9 0.5RCT015 1997 Short Rural 47 14 4 92 7 100.0 0 0 0.0% 0.1 0.2 0.0 0.0RCT021 1997 Short Rural 1 544 2 85,683 158 41.7% 120,002 221 58.3% 1.8 180.7 0.7 73.5RCT023 1997 Long Rural 439 2,576 9 740,037 287 66.2% 377,078 146 33.8% 3.1 0.7 0.8 0.2RobinvaleRVL001 1997 Long Rural 201 631 6 56,888 90 73.4% 20,668 33 26.6% 3.6 1.8 0.2 0.1RVL004 1997 Long Rural 273 357 5 4,612 13 27.0% 12,480 35 73.0% 3.4 1.3 0.2 0.1RVL006 1997 Short Rural 26 869 3 43,955 51 82.7% 9,225 11 17.3% 4.6 17.9 0.2 0.7RVL008 1997 Urban 13 542 6 123,312 228 69.6% 53,870 99 30.4% 7.7 58.9 0.5 4.0SheppartonSTN001 1997 Long Rural 354 1,039 4 155,493 150 70.1% 66,237 64 29.9% 6.0 1.7 0.4 0.1STN002 1997 Short Rural 55 2,817 7 213,645 76 38.9% 336,150 119 61.1% 1.2 2.2 0.3 0.5STN003 1997 Short Rural 132 758 6 36,353 48 89.0% 4,474 6 11.0% 1.6 1.2 0.0 0.0STN004 1997 Urban 19 2,683 7 361,110 135 100.0 0 0 0.0% 2.1 11.3 0.1 0.4STN005 1997 Urban 1 5 7 0 0 0 0 0.0 0.0 0.0 0.0


Doc No.71321 19/09/00 Page B 148



Cust.No

MVA

Total Percust

% oftotal

Total Percust

% oftotal

Total Per100km

Total Per100km

STN006 1997 Urban 5 425 4 428 1 6.2% 6,480 15 93.8% 0.0 0.4 0.1 1.3STN007 1997 Urban 19 1,050 5 24,356 23 96.4% 915 1 3.6% 1.3 7.0 0.0 0.1STN008 1997 Urban 3 313 5 669 2 100.0 0 0 0.0% 0.0 1.1 0.0 0.0SheppartonSHN011 1997 Short Rural 179 992 5 236,506 238 82.7% 49,431 50 17.3% 6.7 3.7 0.4 0.2SHN012 1997 Urban 11 1,197 4 29,617 25 100.0 0 0 0.0% 0.5 4.1 0.0 0.0SHN014 1997 Urban 17 464 7 5,781 12 25.7% 16,740 36 74.3% 1.1 6.7 0.4 2.1SHN021 1997 Urban 2 1,336 4 42,934 32 100.0 0 0 0.0% 2.3 114.9 0.0 0.0SHN022 1997 Urban 1 2,611 11 77,406 30 72.5% 29,300 11 27.5% 1.5 148.7 0.1 7.2SHN023 1997 Urban 20 625 2 2,418 4 100.0 0 0 0.0% 1.1 5.4 0.0 0.0SHN024 1997 Short Rural 175 925 4 43,804 47 89.6% 5,101 6 10.4% 8.5 4.9 0.0 0.0St AlbansSA001 1997 Urban 15 4,846 12 128,587 27 61.1% 81,775 17 38.9% 0.2 1.3 0.1 0.4SA002 1997 Urban 28 5,337 13 637,734 119 92.2% 53,885 10 7.8% 2.1 7.4 0.1 0.3SA003 1997 Urban 9 3,962 9 1,349,473 341 85.0% 237,409 60 15.0% 3.0 33.0 0.3 3.0SA004 1997 Urban 35 5,608 13 589,946 105 99.8% 1,073 0 0.2% 7.2 20.6 0.0 0.0SA005 1997 Urban 21 10,236 12 2,531,226 247 84.0% 481,774 47 16.0% 6.6 31.5 0.2 0.8SA006 1997 Urban 10 976 9 42,452 43 100.0 0 0 0.0% 1.6 16.5 0.0 0.0SA007 1997 Urban 24 6,480 9 625,592 97 90.0% 69,522 11 10.0% 1.7 7.2 0.0 0.2SA008 1997 Urban 14 914 6 119,054 130 98.9% 1,335 1 1.1% 3.7 26.2 0.0 0.1StawellSTL004 1997 Short Rural 25 2,573 5 919,227 357 94.8% 50,555 20 5.2% 4.8 19.3 0.1 0.5STL005 1997 Long Rural 243 1,099 3 203,454 185 46.2% 236,664 215 53.8% 2.2 0.9 1.8 0.7STL006 1997 Long Rural 348 1,433 4 479,227 334 70.7% 198,358 138 29.3% 4.5 1.3 0.9 0.3STL007 1997 Long Rural 207 761 6 641,960 844 96.1% 25,975 34 3.9% 3.0 1.5 0.5 0.2SunshineS019 1997 Urban 1 819 2 5,711 7 32.5% 11,836 14 67.5% 0.1 7.9 0.0 3.5S021 1997 Urban 1 5 0 0 0 0.0% 740 148 100.0 0.0 0.0 0.4 40.0S022 1997 Urban 9 1,467 3 21,653 15 7.7% 259,274 177 92.3% 0.1 1.5 0.6 6.9S023 1997 Urban 1 35 1 4,325 124 67.4% 2,090 60 32.6% 0.8 77.1 0.3 31.4SU001 1997 Urban 14 78 18 3,813 49 100.0 0 0 0.0% 1.0 7.0 0.0 0.1SU002 1997 Urban 23 2,831 15 26,085 9 68.6% 11,940 4 31.4% 0.1 0.5 0.0 0.1SU003 1997 Urban 26 3,000 5 10,571 4 100.0 0 0 0.0% 0.1 0.2 0.0 0.0SU004 1997 Urban 5 498 9 23,146 46 32.6% 47,850 96 67.4% 1.3 26.6 0.4 8.8SU005 1997 Urban 46 2,411 11 1,406,964 584 89.6% 162,475 67 10.4% 8.5 18.5 0.2 0.3SU008 1997 Urban 27 3,239 12 1,446,509 447 99.2% 11,020 3 0.8% 6.1 22.5 0.0 0.0SU009 1997 Urban 25 2,559 10 250,717 98 86.7% 38,300 15 13.3% 2.9 11.7 0.1 0.2SU010 1997 Urban 8 1,173 7 4,694 4 12.6% 32,580 28 87.4% 0.0 0.3 0.1 0.9SU027 1997 Urban 1 550 4 321 1 100.0 0 0 0.0% 0.0 0.4 0.0 0.0SU097 1997 Urban 1 3,290 7 45,173 14 100.0 0 0 0.0% 0.1 9.9 0.0 0.1Swan HillSHL001 1997 Long Rural 263 383 1 94,413 247 43.6% 122,068 319 56.4% 1.4 0.5 1.6 0.6SHL002 1997 Long Rural 406 1,484 5 361,484 244 45.4% 434,582 293 54.6% 2.3 0.6 1.3 0.3SHL004 1997 Long Rural 240 1,156 4 307,467 266 85.6% 51,640 45 14.4% 2.5 1.0 0.3 0.1SHL005 1997 Long Rural 341 1,231 4 568,391 462 76.6% 173,984 141 23.4% 3.1 0.9 1.1 0.3SHL007 1997 Urban 19 2,093 8 9,891 5 60.7% 6,396 3 39.3% 1.1 6.0 0.1 0.4SHL008 1997 Urban 8 2,083 7 2,187 1 1.8% 118,560 57 98.2% 0.0 0.2 0.2 2.3


Doc No.71321 19/09/00 Page B 149



Cust.No

MVA

Total Percust

% oftotal

Total Percust

% oftotal

Total Per100km

Total Per100km

TerangTRG001 1997 Short Rural 148 585 8 431,615 738 86.1% 69,437 119 13.9% 4.1 2.8 0.5 0.3TRG002 1997 Long Rural 505 2,048 5 575,777 281 74.5% 196,920 96 25.5% 5.4 1.1 0.4 0.1TRG003 1997 Long Rural 363 1,091 7 588,193 539 84.9% 104,751 96 15.1% 7.6 2.1 0.3 0.1TRG004 1997 Short Rural 14 1,050 3 104,559 100 79.7% 26,636 25 20.3% 0.7 5.0 0.3 1.8TRG005 1997 Long Rural 417 2,476 9 506,912 205 57.1% 380,327 154 42.9% 4.0 1.0 0.4 0.1WarnamboolWBL001 1997 Urban 13 2,115 6 28,842 14 77.0% 8,595 4 23.0% 1.2 9.6 0.1 0.7WBL002 1997 Short Rural 25 1,948 7 841,153 432 93.3% 60,574 31 6.7% 3.1 12.4 0.1 0.4WBL003 1997 Long Rural 275 408 5 179,562 440 61.1% 114,504 281 38.9% 5.2 1.9 0.9 0.3WBL004 1997 Short Rural 28 2,137 6 628,557 294 99.8% 1,560 1 0.2% 4.5 15.9 0.0 0.0WBL005 1997 Short Rural 108 837 2 141,053 169 92.9% 10,727 13 7.1% 1.5 1.4 0.2 0.2WBL007 1997 Short Rural 28 2,985 6 177,097 59 73.3% 64,621 22 26.7% 0.5 1.8 0.1 0.4WBL008 1997 Short Rural 38 1,852 5 610,923 330 99.8% 960 1 0.2% 1.2 3.3 0.0 0.0WBL010 1997 Urban 10 1,143 6 304,509 266 99.5% 1,455 1 0.5% 2.7 26.8 0.1 0.8Waurn PondsWPD011 1997 Short Rural 149 377 2 28,778 76 29.2% 69,893 185 70.8% 2.5 1.7 0.7 0.5WPD014 1997 Long Rural 220 2,946 10 357,449 121 85.2% 62,245 21 14.8% 3.5 1.6 0.1 0.0WPD022 1997 Short Rural 86 4,818 10 731,889 152 81.6% 164,735 34 18.4% 8.4 9.8 0.2 0.2WPD024 1997 Short Rural 32 6,799 7 956,428 141 94.9% 51,446 8 5.1% 2.6 8.0 0.0 0.1WPD031 1997 Short Rural 25 1,810 6 66,697 37 38.7% 105,637 58 61.3% 0.3 1.0 0.3 1.2WPD033 1997 Urban 14 1,147 5 13,430 12 32.9% 27,362 24 67.1% 1.3 8.9 0.1 0.6WerribeeWBE031 1997 Urban 28 4,503 6 95,090 21 58.1% 68,565 15 41.9% 1.1 4.1 0.0 0.2WBE032 1997 Short Rural 74 5,133 9 544,300 106 97.5% 13,855 3 2.5% 3.3 4.4 0.0 0.0WBE033 1997 Urban 48 3,285 11 524,927 160 93.2% 38,465 12 6.8% 4.0 8.4 0.1 0.1WBE034 1997 Urban 18 2,944 9 174,816 59 61.4% 109,690 37 38.6% 1.9 10.7 0.1 0.7WinchelseaWIN011 1997 Short Rural 76 617 2 106,997 173 34.1% 206,615 335 65.9% 10.1 13.3 1.7 2.2WIN012 1997 Long Rural 432 1,399 4 878,200 628 92.7% 69,155 49 7.3% 21.5 5.0 0.3 0.1WIN013 1997 Short Rural 77 500 1 83,255 167 46.6% 95,563 191 53.4% 10.0 13.0 2.3 3.0WoodendWND011 1997 Short Rural 170 1,869 6 156,873 84 95.2% 7,888 4 4.8% 1.4 0.8 0.0 0.0WND012 1997 Short Rural 79 3,063 9 109,592 36 43.9% 139,915 46 56.1% 0.4 0.5 0.2 0.2WND013 1997 Long Rural 434 3,529 9 1,195,994 339 83.1% 242,856 69 16.9% 4.9 1.1 1.2 0.3WND014 1997 Short Rural 56 1,948 6 38,319 20 92.4% 3,146 2 7.6% 0.6 1.0 0.1 0.1WND022 1997 Long Rural 283 2,472 8 528,300 214 84.5% 97,170 39 15.5% 4.1 1.5 0.1 0.0WND023 1997 Long Rural 342 1,662 4 145,997 88 58.6% 103,008 62 41.4% 1.0 0.3 0.7 0.2WND024 1997 Long Rural 209 1,731 3 476,854 275 97.4% 12,648 7 2.6% 3.5 1.7 0.1 0.0ART031 1998 Short Rural 59 1,196 3 321,686 269 99.1% 3,000 3 0.9% 5.1 8.7 0.0 0.0ART033 1998 Long Rural 651 1,991 3 629,505 316 84.3% 116,948 59 15.7% 3.4 0.5 0.4 0.1ART034 1998 Short Rural 24 1,947 3 400,970 206 89.5% 47,258 24 10.5% 2.7 11.4 0.1 0.4AltonaAL002 1998 Urban 17 1,523 4 24,731 16 85.0% 4,354 3 15.0% 0.2 1.0 0.2 1.4AL006 1998 Urban 17 2 0 0 0 0.0% 10,770 5,385 100.0 0.0 0.0 0.5 2.9AL007 1998 Urban 1 1,786 0 58,212 33 85.7% 9,675 5 14.3% 0.8 85.0 0.0 1.6AL012 1998 Urban 14 2,628 0 431,665 164 100.0 0 0 0.0% 4.2 29.6 0.0 0.0


Doc No.71321 19/09/00 Page B 150



Cust.No

MVA

Total Percust

% oftotal

Total Percust

% oftotal

Total Per100km

Total Per100km

AL014 1998 Urban 3 1 -9 0 0 0 0 1.0 33.3 0.0 0.0

AltonaAC031 1998 Urban 4 4 4 480 120 100.0 0 0 0.0% 1.0 25.0 0.0 0.0Bacchus MarshBMH003 1998 Long Rural 365 3,377 5 1,103,456 327 96.7% 37,136 11 3.3% 10.9 3.0 0.1 0.0BMH004 1998 Short Rural 44 2,929 7 263,421 90 82.8% 54,820 19 17.2% 5.4 12.2 0.1 0.3BMH005 1998 Short Rural 9 107 0 0 0 0 0 0.0 0.2 0.0 0.0BMH006 1998 Short Rural 130 946 7 192,375 203 99.7% 655 1 0.3% 4.4 3.4 0.0 0.0Ballarat NorthBAN001 1998 Long Rural 286 2,807 6 45,889 16 55.9% 36,140 13 44.1% 1.2 0.4 0.1 0.0BAN002 1998 Urban 15 803 0 313,189 390 86.7% 48,059 60 13.3% 17.8 118.7 0.5 3.3BAN003 1998 Urban 4 409 0 1,880 5 24.2% 5,880 14 75.8% 2.1 53.2 0.1 3.7BAN004 1998 Urban 17 647 0 1,011 2 91.0% 100 0 9.0% 2.1 12.3 0.0 0.0BAN005 1998 Urban 11 1,440 0 20,638 14 100.0 0 0 0.0% 0.2 1.9 0.0 0.0BAN006 1998 Urban 17 4,515 0 1,118,402 248 93.9% 72,329 16 6.1% 7.9 46.7 0.2 1.2BAN007 1998 Short Rural 75 3,733 11 72,551 19 63.8% 41,245 11 36.2% 0.2 0.3 0.0 0.0BAN008 1998 Long Rural 302 4,172 9 1,449,462 347 97.2% 41,945 10 2.8% 8.3 2.8 0.2 0.1BAN009 1998 Long Rural 259 2,512 8 828,611 330 98.5% 12,909 5 1.5% 5.9 2.3 0.1 0.1BAN011 1998 Short Rural 60 1,759 4 576,686 328 84.6% 105,332 60 15.4% 10.4 17.3 0.3 0.5BAN013 1998 Urban 7 506 0 16,869 33 98.6% 240 0 1.4% 1.3 18.7 0.1 1.2BAN015 1998 Short Rural 51 3,446 7 1,247,642 362 99.3% 8,710 3 0.7% 15.1 29.7 0.0 0.0Ballarat SouthBAS011 1998 Long Rural 602 3,098 9 546,027 176 84.6% 99,498 32 15.4% 6.3 1.0 0.5 0.1BAS012 1998 Urban 10 2,165 0 10,476 5 50.5% 10,250 5 49.5% 1.1 11.0 0.0 0.2BAS013 1998 Short Rural 35 1,907 7 152,619 80 93.9% 9,975 5 6.1% 2.2 6.4 0.0 0.0BAS014 1998 Short Rural 1 2,940 7 49,406 17 59.4% 33,759 11 40.6% 3.2 322.7 0.1 11.6BAS021 1998 Long Rural 362 3,774 9 356,335 94 88.9% 44,481 12 11.1% 3.5 1.0 0.2 0.1BAS022 1998 Long Rural 373 4,408 8 1,685,139 382 95.1% 86,247 20 4.9% 7.8 2.1 0.2 0.1BAS023 1998 Short Rural 30 2,878 6 585,598 203 97.3% 16,385 6 2.7% 2.3 7.7 0.0 0.1BAS024 1998 Urban 3 102 0 848 8 50.8% 822 8 49.2% 0.1 2.3 0.0 1.3BAS034 1998 Urban 6 3,018 0 333,863 111 95.2% 16,778 6 4.8% 4.3 71.1 0.0 0.6BendigoBGO011 1998 Urban 1 581 0 23,196 40 54.7% 19,184 33 45.3% 0.4 38.2 0.1 12.6BGO012 1998 Short Rural 34 3,835 8 1,051,926 274 95.9% 45,368 12 4.1% 2.8 8.2 0.1 0.2BGO013 1998 Long Rural 240 4,194 11 219,956 52 64.9% 118,903 28 35.1% 1.6 0.7 0.1 0.0BGO021 1998 Urban 6 1,648 0 257,532 156 95.0% 13,430 8 5.0% 1.8 29.4 0.2 3.1BGO022 1998 Short Rural 139 4,450 9 1,708,317 384 91.7% 153,727 35 8.3% 3.3 2.4 0.1 0.1BGO023 1998 Urban 2 1,517 0 6,112 4 60.1% 4,050 3 39.9% 0.5 24.0 0.0 0.9BendigoBET001 1998 Urban 8 2,697 0 56,316 21 77.8% 16,024 6 22.2% 0.3 3.3 0.1 1.0BET002 1998 Short Rural 31 2,718 7 224,647 83 99.8% 465 0 0.2% 3.6 11.6 0.0 0.0BET003 1998 Urban 7 309 0 1,242 4 100.0 0 0 0.0% 0.1 0.9 0.0 0.0BET004 1998 Short Rural 50 2,146 6 273,027 127 84.0% 52,050 24 16.0% 1.6 3.1 0.1 0.2BrooklynBLT016 1998 Urban 10 94 0 2,283 24 73.1% 840 9 26.9% 2.4 23.8 0.1 0.7BLT017 1998 Urban 10 810 0 74,574 92 99.2% 595 1 0.8% 1.5 15.2 0.0 0.0BLT020 1998 Urban 17 83 0 12,877 155 63.4% 7,420 89 36.6% 3.0 17.6 0.3 1.6


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Cust.No

MVA

Total Percust

% oftotal

Total Percust

% oftotal

Total Per100km

Total Per100km

BLT021 1998 Urban 1 2 0 583 292 57.4% 433 217 42.6% 1.0 100.0 0.5 50.0BLT022 1998 Short Rural 21 1,564 6 55,323 35 99.0% 570 0 1.0% 3.5 16.6 0.0 0.0BLT030 1998 Urban 17 1,859 0 258,150 139 98.2% 4,668 3 1.8% 5.6 33.1 0.0 0.0BLT031 1998 Urban 18 1,187 6 52,538 44 56.9% 39,725 33 43.1% 0.7 3.9 0.1 0.6CamperdownCDN001 1998 Long Rural 284 1,754 8 496,711 283 88.4% 65,407 37 11.6% 7.8 2.7 0.1 0.0CDN002 1998 Short Rural 175 541 3 289,866 536 99.9% 275 1 0.1% 8.0 4.6 0.0 0.0CDN003 1998 Short Rural 18 1,551 4 92,773 60 81.9% 20,445 13 18.1% 1.7 9.5 0.0 0.2CDN004 1998 Long Rural 285 811 3 144,120 178 94.7% 7,990 10 5.3% 5.4 1.9 0.3 0.1CDN006 1998 Long Rural 315 1,019 3 604,601 593 88.0% 82,261 81 12.0% 3.4 1.1 0.5 0.1CastlemaineCMN001 1998 Short Rural 100 1,419 2 141,820 100 96.7% 4,845 3 3.3% 1.1 1.1 0.0 0.0CMN002 1998 Long Rural 289 2,336 3 276,070 118 75.7% 88,801 38 24.3% 4.7 1.6 0.1 0.1CMN003 1998 Long Rural 202 2,460 5 533,349 217 94.9% 28,905 12 5.1% 4.5 2.2 0.0 0.0CMN004 1998 Short Rural 167 1,329 3 442,847 333 92.4% 36,675 28 7.6% 7.6 4.5 0.1 0.1CMN005 1998 Short Rural 20 961 0 27,562 29 99.2% 210 0 0.8% 1.3 6.4 0.0 0.2CharltonCTN001 1998 Long Rural 575 1,763 4 960,275 545 96.7% 32,665 19 3.3% 18.1 3.2 0.1 0.0CTN002 1998 Long Rural 368 1,164 2 505,742 434 94.4% 29,891 26 5.6% 11.9 3.2 0.1 0.0CTN003 1998 Long Rural 508 1,397 4 331,186 237 79.9% 83,275 60 20.1% 10.5 2.1 0.4 0.1CTN004 1998 Short Rural 180 1,166 4 94,545 81 100.0 0 0 0.0% 11.0 6.1 0.0 0.0CTN005 1998 Urban 8 619 2 3,105 5 21.1% 11,625 19 78.9% 9.7 121.3 0.2 3.0CTN006 1998 Long Rural 1541 2,113 6 1,533,459 726 98.2% 28,745 14 1.8% 18.0 1.2 0.2 0.0Cobram EastCME014 1998 Short Rural 134 2,016 8 341,796 170 94.6% 19,453 10 5.4% 8.9 6.6 0.1 0.1CME015 1998 Short Rural 163 594 10 115,596 195 99.3% 840 1 0.7% 8.3 5.1 0.0 0.0CME016 1998 Long Rural 298 1,732 7 1,545,815 893 95.0% 82,065 47 5.0% 22.0 7.4 0.5 0.2CME021 1998 Urban 1 1,444 0 186,453 129 85.2% 32,301 22 14.8% 4.9 493.8 0.1 6.6CME022 1998 Urban 4 820 0 26,079 32 52.3% 23,802 29 47.7% 3.5 88.0 0.2 5.4CohunaCHA003 1998 Short Rural 111 1,222 5 357,070 292 91.0% 35,446 29 9.0% 7.4 6.6 0.1 0.1CHA005 1998 Long Rural 499 1,217 7 279,353 230 64.0% 157,238 129 36.0% 3.9 0.8 0.5 0.1CHA006 1998 Long Rural 667 1,518 4 145,504 96 88.6% 18,808 12 11.4% 4.2 0.6 0.3 0.0ColacCLC001 1998 Short Rural 14 1,834 3 22,774 12 30.1% 52,895 29 69.9% 0.1 0.9 0.2 1.1CLC002 1998 Urban 14 2,339 0 85,962 37 91.3% 8,240 4 8.7% 0.4 2.8 0.0 0.1CLC003 1998 Long Rural 382 1,521 6 891,622 586 95.2% 45,150 30 4.8% 7.9 2.1 0.3 0.1CLC004 1998 Short Rural 193 1,244 5 271,843 219 55.0% 222,384 179 45.0% 2.2 1.2 0.5 0.3CLC005 1998 Short Rural 104 1,685 3 427,516 254 93.0% 32,300 19 7.0% 9.8 9.5 0.1 0.1CLC006 1998 Long Rural 408 2,697 5 1,191,170 442 85.2% 207,089 77 14.8% 7.9 1.9 0.3 0.1CLC008 1998 Long Rural 312 2,605 6 2,391,656 918 82.3% 513,283 197 17.7% 14.9 4.8 0.7 0.2CorioCRO013 1998 Short Rural 147 3,850 7 563,589 146 94.7% 31,283 8 5.3% 7.3 5.0 0.0 0.0CRO021 1998 Urban 9 639 0 90,919 142 84.1% 17,210 27 15.9% 2.2 24.9 0.1 1.1CRO022 1998 Urban 11 3,313 0 711,535 215 95.5% 33,360 10 4.5% 2.9 26.0 0.1 0.9CRO023 1998 Short Rural 4 247 1 80,484 326 100.0 0 0 0.0% 3.4 85.3 0.0 0.0


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Cust.No

MVA

Total Percust

% oftotal

Total Percust

% oftotal

Total Per100km

Total Per100km

CRO031 1998 Urban 1 1 0 157 157 100.0 0 0 0.0% 1.0 100.0 0.0 0.0CRO032 1998 Urban 1 3 0 108 36 100.0 0 0 0.0% 2.0 200.0 0.0 0.0CRO033 1998 Urban 4 19 0 3,933 207 85.6% 660 35 14.4% 1.2 28.9 0.1 2.6CRO034 1998 Urban 17 1,295 0 101,525 78 100.0 0 0 0.0% 0.6 3.7 0.0 0.0DrysdaleDDL011 1998 Urban 1 2,909 0 360,203 124 81.3% 82,923 29 18.7% 2.0 201.8 0.2 15.2DDL012 1998 Short Rural 70 3,314 5 303,822 92 94.8% 16,800 5 5.2% 4.4 6.3 0.0 0.0DDL013 1998 Short Rural 88 2,877 5 280,066 97 89.6% 32,580 11 10.4% 2.3 2.6 0.1 0.1DDL014 1998 Short Rural 24 2,623 0 145,017 55 16.3% 744,355 284 83.7% 2.4 10.0 0.8 3.5DDL022 1998 Short Rural 60 2,922 6 97,913 34 89.5% 11,470 4 10.5% 4.4 7.3 0.0 0.0DDL023 1998 Short Rural 84 3,495 8 1,273,806 364 78.0% 359,575 103 22.0% 15.1 18.0 0.5 0.5DDL024 1998 Short Rural 85 1,604 5 84,259 53 11.8% 628,281 392 88.2% 3.6 4.2 1.1 1.3EaglehawkEHK021 1998 Urban 9 418 0 4,570 11 86.8% 698 2 13.2% 0.2 1.8 0.0 0.4EHK022 1998 Long Rural 321 3,891 9 236,907 61 66.5% 119,595 31 33.5% 3.7 1.2 0.2 0.1EHK023 1998 Urban 4 628 0 4,589 7 100.0 0 0 0.0% 0.1 2.1 0.0 0.0EHK024 1998 Long Rural 915 3,365 12 478,360 142 67.1% 234,814 70 32.9% 1.6 0.2 0.4 0.0EHK032 1998 Short Rural 61 1,814 5 87,488 48 53.1% 77,257 43 46.9% 0.6 0.9 0.2 0.3EHK033 1998 Urban 3 2,214 0 117,816 53 90.3% 12,600 6 9.7% 0.5 18.1 0.0 1.1EHK034 1998 Urban 2 1,020 0 27,748 27 97.8% 620 1 2.2% 0.3 14.5 0.0 0.2EchucaECA001 1998 Urban 8 2,052 0 104,486 51 94.2% 6,480 3 5.8% 2.1 26.4 0.0 0.2ECA003 1998 Short Rural 45 2,386 10 75,053 31 91.8% 6,660 3 8.2% 1.3 2.9 0.0 0.0ECA005 1998 Long Rural 254 626 6 105,874 169 47.6% 116,464 186 52.4% 4.2 1.6 0.7 0.3ECA007 1998 Long Rural 371 1,077 10 155,344 144 33.6% 306,439 285 66.4% 1.2 0.3 1.0 0.3ECA010 1998 Urban 6 1,778 0 237,153 133 74.3% 82,117 46 25.7% 3.0 50.0 0.2 2.9ECA012 1998 Long Rural 324 2,195 9 478,193 218 89.2% 57,647 26 10.8% 3.6 1.1 0.1 0.0Ford NorthFNS011 1998 Short Rural 105 2,679 8 302,694 113 87.1% 44,986 17 12.9% 1.3 1.2 0.1 0.1FNS012 1998 Short Rural 70 3,406 7 312,646 92 36.9% 534,700 157 63.1% 2.2 3.1 0.5 0.7FNS021 1998 Urban 1 784 4 18,624 24 100.0 0 0 0.0% 0.4 44.3 0.0 0.0FNS022 1998 Short Rural 167 556 6 22,542 41 92.8% 1,750 3 7.2% 1.3 0.8 0.0 0.0FNS032 1998 Short Rural 16 239 3 129,877 543 90.6% 13,515 57 9.4% 4.4 27.2 0.2 1.0GeelongGL011 1998 Urban 15 1,511 0 92,105 61 85.6% 15,510 10 14.4% 1.2 8.3 0.1 0.4GL012 1998 Urban 6 1,111 0 70,860 64 100.0 0 0 0.0% 0.9 15.5 0.0 0.7GL013 1998 Urban 10 2,337 0 80,063 34 98.7% 1,084 0 1.3% 1.2 12.2 0.0 0.2GL014 1998 Urban 19 3,053 0 1,620,935 531 99.2% 12,555 4 0.8% 6.8 35.9 0.0 0.1GL015 1998 Urban 3 312 0 20,873 67 100.0 0 0 0.0% 0.4 13.6 0.0 0.0GL021 1998 Short Rural 32 5,568 0 1,189,862 214 89.9% 133,255 24 10.1% 6.5 20.2 0.1 0.2GL022 1998 Urban 19 3,432 0 245,153 71 90.9% 24,570 7 9.1% 0.7 3.6 0.0 0.1GL023 1998 Urban 6 1,031 0 19,264 19 100.0 0 0 0.0% 0.2 2.9 0.0 0.0GL024 1998 Long Rural 398 4,032 0 957,059 237 90.3% 102,532 25 9.7% 1.9 0.5 0.1 0.0Geelong BGB011 1998 Urban 1 11 0 280 25 16.2% 1,450 132 83.8% 0.3 45.5 0.5 75.8GB012 1998 Urban 3 13 0 2,415 186 39.3% 3,734 287 60.7% 1.5 51.3 0.8 28.2


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Cust.No

MVA

Total Percust

% oftotal

Total Percust

% oftotal

Total Per100km

Total Per100km

GB014 1998 Urban 3 3 0 227 76 12.4% 1,602 534 87.6% 1.7 55.6 1.7 55.6GB031 1998 Urban 2 215 0 8,477 39 100.0 0 0 0.0% 1.3 63.0 0.0 0.0Geelong CityGCY012 1998 Urban 1 518 0 21,106 41 89.2% 2,552 5 10.8% 0.4 42.0 0.0 1.5GCY013 1998 Urban 0 432 0 8,276 19 53.7% 7,125 16 46.3% 0.2 59.4 0.1 19.3GCY014 1998 Urban 1 3,277 10 348,371 106 100.0 0 0 0.0% 2.0 201.8 0.0 0.0GCY021 1998 Urban 1 276 7 3,386 12 100.0 0 0 0.0% 0.1 12.7 0.0 0.0GCY022 1998 Urban 1 431 7 40,731 95 100.0 0 0 0.0% 0.4 41.8 0.0 0.0GCY023 1998 Urban 4 3,246 0 510,472 157 87.4% 73,593 23 12.6% 5.4 134.3 0.1 3.6GCY024 1998 Urban 7 2,069 0 30,221 15 95.0% 1,582 1 5.0% 0.2 2.4 0.0 0.0Geelong EastGLE011 1998 Urban 16 258 0 53,915 209 99.2% 455 2 0.8% 4.8 29.9 0.1 0.3GLE012 1998 Urban 8 3,426 0 222,787 65 95.4% 10,658 3 4.6% 2.6 31.9 0.0 0.2GLE013 1998 Short Rural 59 3,788 7 140,490 37 65.6% 73,810 19 34.4% 2.4 4.1 0.1 0.2GLE021 1998 Short Rural 120 437 7 650,424 1,488 89.8% 74,181 170 10.2% 31.5 26.3 0.6 0.5GLE023 1998 Urban 4 1 0 0 0 0 0 1.0 25.0 0.0 0.0GLE024 1998 Short Rural 35 4,926 9 439,074 89 87.2% 64,435 13 12.8% 1.6 4.5 0.1 0.2GLE031 1998 Urban 15 2,571 0 92,317 36 47.3% 102,712 40 52.7% 3.3 21.8 0.2 1.3GLE032 1998 Urban 7 2,599 0 30,965 12 50.9% 29,896 12 49.1% 0.8 11.4 0.2 2.4GLE033 1998 Urban 16 406 0 319,474 787 89.7% 36,856 91 10.3% 12.4 77.8 0.8 4.9HamiltonHTN001 1998 Long Rural 376 840 2 271,853 324 94.2% 16,861 20 5.8% 3.3 0.9 0.2 0.1HTN002 1998 Long Rural 595 2,179 4 461,859 212 80.7% 110,129 51 19.3% 4.5 0.7 0.3 0.0HTN003 1998 Long Rural 321 1,773 3 1,366,673 771 92.5% 111,462 63 7.5% 9.0 2.8 0.5 0.2HTN004 1998 Short Rural 34 3,081 6 626,241 203 98.4% 10,055 3 1.6% 3.4 9.9 0.0 0.1HTN005 1998 Urban 3 2,683 0 329,394 123 87.0% 49,045 18 13.0% 2.5 85.0 0.1 4.7HTN006 1998 Long Rural 963 2,481 5 276,719 112 98.1% 5,250 2 1.9% 5.0 0.5 0.0 0.0HorshamHSM001 1998 Long Rural 744 2,244 5 1,151,150 513 93.0% 87,097 39 7.0% 6.7 0.9 0.7 0.1HSM002 1998 Long Rural 1336 2,930 5 3,274,932 1,118 96.8% 107,565 37 3.2% 11.8 0.9 0.6 0.0HSM003 1998 Long Rural 305 1,448 3 279,626 193 82.6% 58,909 41 17.4% 8.8 2.9 0.5 0.2HSM004 1998 Long Rural 471 1,985 4 1,540,778 776 95.9% 66,503 34 4.1% 7.2 1.5 0.6 0.1HSM005 1998 Long Rural 268 1,567 4 49,490 32 51.9% 45,843 29 48.1% 0.3 0.1 0.4 0.2HSM006 1998 Short Rural 172 2,068 5 1,213,339 587 88.6% 156,476 76 11.4% 7.3 4.3 0.9 0.5HSM009 1998 Urban 20 2,379 0 193,174 81 80.3% 47,308 20 19.7% 1.0 5.2 0.1 0.5HSM010 1998 Short Rural 27 3,038 7 19,788 7 17.2% 95,378 31 82.8% 4.3 15.8 0.1 0.4KerangKGT002 1998 Short Rural 41 2,060 6 688,781 334 94.3% 41,999 20 5.7% 5.2 12.7 0.1 0.2KGT003 1998 Long Rural 308 1,245 4 256,426 206 50.9% 247,774 199 49.1% 4.2 1.4 1.0 0.3KGT004 1998 Long Rural 325 799 2 546,796 684 99.1% 5,090 6 0.9% 4.7 1.4 0.0 0.0KoroitKRT012 1998 Long Rural 225 835 2 741,678 888 93.4% 52,814 63 6.6% 12.4 5.5 0.3 0.1KRT013 1998 Long Rural 232 1,695 7 425,163 251 62.5% 255,081 150 37.5% 16.6 7.2 0.6 0.3KRT021 1998 Long Rural 371 152 7 303,973 2,000 85.8% 50,222 330 14.2% 31.9 8.6 1.6 0.4KRT022 1998 Urban 11 2,381 0 569,657 239 96.0% 23,970 10 4.0% 4.2 38.2 0.1 0.6KRT023 1998 Long Rural 1 1,330 0 84,509 64 100.0 0 0 0.0% 1.1 113.8 0.0 0.0


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Cust.No

MVA

Total Percust

% oftotal

Total Percust

% oftotal

Total Per100km

Total Per100km

KyabramKYM001 1998 Short Rural 156 1,203 10 150,186 125 87.1% 22,254 18 12.9% 6.4 4.1 0.2 0.1KYM002 1998 Long Rural 304 1,639 12 589,384 360 90.4% 62,794 38 9.6% 4.1 1.3 0.1 0.0KYM003 1998 Long Rural 392 1,507 7 667,036 443 46.9% 754,834 501 53.1% 12.1 3.1 1.5 0.4KYM004 1998 Short Rural 195 1,489 5 117,960 79 94.7% 6,552 4 5.3% 5.9 3.0 0.0 0.0KYM005 1998 Urban 25 2,512 9 81,521 32 82.6% 17,220 7 17.4% 1.3 5.1 0.0 0.1KYM006 1998 Short Rural 85 418 9 131,531 315 89.4% 15,665 37 10.6% 4.7 5.6 0.2 0.3LavertonLV001 1998 Urban 19 2,647 0 39,258 15 78.2% 10,975 4 21.8% 1.1 5.9 0.0 0.1LV002 1998 Short Rural 83 118 10 757 6 30.0% 1,770 15 70.0% 1.3 1.6 0.1 0.1LV003 1998 Short Rural 73 20 9 994 50 53.5% 865 43 46.5% 1.6 2.1 0.1 0.2LV004 1998 Urban 33 3,991 9 159,394 40 91.7% 14,510 4 8.3% 5.3 16.1 0.0 0.0LV005 1998 Urban 14 617 0 149,575 242 100.0 0 0 0.0% 4.3 30.8 0.0 0.0LV006 1998 Urban 68 5,424 13 1,126,509 208 100.0 0 0 0.0% 5.1 7.6 0.0 0.0LV007 1998 Urban 19 1,488 0 36,017 24 100.0 0 0 0.0% 1.2 6.5 0.0 0.0LV008 1998 Short Rural 90 3,231 10 665,140 206 92.9% 50,479 16 7.1% 8.3 9.2 0.3 0.3LV009 1998 Urban 24 4,104 0 47,879 12 100.0 0 0 0.0% 0.1 0.5 0.0 0.0MaryboroughMRO002 1998 Urban 1 2 0 133 67 100.0 0 0 0.0% 0.5 50.0 0.0 0.0MRO004 1998 Short Rural 16 1,987 4 213,610 108 100.0 0 0 0.0% 2.2 14.0 0.0 0.0MRO005 1998 Long Rural 332 1,707 4 651,668 382 87.2% 95,950 56 12.8% 3.0 0.9 0.6 0.2MRO006 1998 Urban 4 625 0 5,210 8 100.0 0 0 0.0% 0.1 2.5 0.0 0.0MRO007 1998 Long Rural 277 1,628 4 572,565 352 98.8% 6,728 4 1.2% 6.9 2.5 0.1 0.0MRO008 1998 Short Rural 192 2,519 5 923,688 367 96.5% 33,138 13 3.5% 2.8 1.5 0.1 0.0MeltonMLN011 1998 Short Rural 78 4,918 11 772,406 157 99.9% 680 0 0.1% 4.7 6.0 0.0 0.0MLN012 1998 Short Rural 136 3,847 8 456,534 119 95.2% 23,230 6 4.8% 5.4 4.0 0.0 0.0MLN021 1998 Short Rural 92 792 7 580,409 733 95.3% 28,600 36 4.7% 10.1 11.0 0.3 0.3MLN024 1998 Urban 31 3,147 9 84,491 27 43.8% 108,433 34 56.2% 2.2 7.2 0.1 0.4MerbeinMBN012 1998 Short Rural 43 1,870 6 183,778 98 36.0% 327,376 175 64.0% 1.3 3.0 0.5 1.2MBN013 1998 Short Rural 43 432 3 50,216 116 26.7% 137,777 319 73.3% 1.3 3.0 1.4 3.3MBN014 1998 Short Rural 93 700 5 114,402 163 76.8% 34,606 49 23.2% 2.3 2.4 0.4 0.4MBN021 1998 Short Rural 125 1,184 4 225,313 190 58.4% 160,428 135 41.6% 1.2 0.9 0.4 0.3MBN022 1998 Short Rural 57 647 3 102,815 159 66.1% 52,678 81 33.9% 2.1 3.6 0.3 0.4MilduraMDA022 1998 Urban 12 2,955 0 185,226 63 87.6% 26,140 9 12.4% 1.1 9.6 0.1 0.5MDA023 1998 Short Rural 103 1,879 8 100,682 54 58.6% 71,250 38 41.4% 0.7 0.7 0.2 0.2MDA024 1998 Urban 14 599 0 255,407 426 90.1% 28,015 47 9.9% 4.4 31.6 0.3 2.3MDA031 1998 Short Rural 29 1,195 7 44,646 37 67.7% 21,330 18 32.3% 0.5 1.6 0.1 0.4MDA032 1998 Short Rural 42 2,419 10 155,260 64 78.4% 42,788 18 21.6% 1.2 2.9 0.1 0.2MDA033 1998 Urban 1 2,353 0 49,126 21 36.8% 84,428 36 63.2% 1.2 119.4 0.1 11.3MooroopnaMNA014 1998 Long Rural 286 1,847 8 470,111 255 59.4% 321,405 174 40.6% 6.0 2.1 0.6 0.2MNA021 1998 Short Rural 49 2,203 12 594,356 270 95.1% 30,687 14 4.9% 8.3 16.9 0.1 0.2MNA022 1998 Urban 6 505 0 61,726 122 100.0 0 0 0.0% 2.1 34.6 0.0 0.0


Doc No.71321 19/09/00 Page B 155



Cust.No

MVA

Total Percust

% oftotal

Total Percust

% oftotal

Total Per100km

Total Per100km

MNA024 1998 Urban 15 914 0 2,672 3 8.5% 28,584 31 91.5% 2.1 13.7 0.1 0.9MNA034 1998 Long Rural 354 1,841 6 493,598 268 95.1% 25,199 14 4.9% 6.8 1.9 0.2 0.0NhillNHL015 1998 Long Rural 656 1,779 3 1,715,932 965 98.1% 33,418 19 1.9% 20.0 3.0 0.7 0.1NHL016 1998 Short Rural 192 1,409 4 474,296 337 91.8% 42,091 30 8.2% 9.5 4.9 0.4 0.2NHL031 1998 Long Rural 687 1,432 0 2,164,974 1,512 93.4% 151,802 106 6.6% 45.6 6.6 1.6 0.2NurmukaNKA001 1998 Long Rural 217 1,092 3 176,014 161 87.0% 26,291 24 13.0% 4.0 1.9 0.2 0.1NKA002 1998 Long Rural 261 2,168 8 144,549 67 53.0% 128,398 59 47.0% 4.3 1.7 0.3 0.1NKA003 1998 Short Rural 107 459 5 40,008 87 59.2% 27,589 60 40.8% 0.5 0.4 0.2 0.2NKA004 1998 Short Rural 132 1,986 8 273,118 138 80.5% 66,334 33 19.5% 4.6 3.5 0.1 0.1NKA005 1998 Short Rural 165 783 4 120,297 154 52.9% 107,190 137 47.1% 7.0 4.3 0.7 0.4NKA006 1998 Long Rural 316 717 5 160,593 224 82.8% 33,464 47 17.2% 3.5 1.1 0.3 0.1OuyenOYN001 1998 Long Rural 661 1,049 2 664,412 633 98.2% 12,448 12 1.8% 8.5 1.3 0.2 0.0OYN003 1998 Long Rural 262 451 1 414,703 920 99.9% 465 1 0.1% 11.8 4.5 0.0 0.0OYN005 1998 Long Rural 576 1,559 3 2,678,248 1,718 94.4% 158,845 102 5.6% 28.0 4.9 0.6 0.1OYN007 1998 Urban 1 636 0 39,359 62 56.0% 30,960 49 44.0% 4.3 426.4 0.1 11.3PortlandPLD001 1998 Long Rural 590 1,701 3 183,858 108 96.1% 7,387 4 3.9% 3.3 0.6 0.0 0.0PLD002 1998 Urban 3 13 0 277 21 35.2% 510 39 64.8% 1.4 46.2 0.2 5.1PLD003 1998 Short Rural 30 1,155 5 504,836 437 95.8% 22,010 19 4.2% 8.3 27.7 0.1 0.4PLD004 1998 Short Rural 33 2,497 4 68,690 28 78.5% 18,775 8 21.5% 1.7 5.1 0.1 0.2PLD005 1998 Short Rural 11 159 3 1,471 9 89.4% 175 1 10.6% 2.3 20.7 0.0 0.1PLD006 1998 Short Rural 104 2,611 6 1,475,369 565 99.7% 4,426 2 0.3% 9.9 9.5 0.0 0.0Red CliffsRCT011 1998 Short Rural 46 627 2 135,199 216 72.1% 52,275 83 27.9% 1.5 3.4 0.4 0.9RCT013 1998 Long Rural 222 812 7 613,667 756 89.5% 72,100 89 10.5% 9.5 4.3 0.3 0.1RCT014 1998 Short Rural 165 831 11 26,578 32 63.9% 15,020 18 36.1% 2.2 1.3 0.1 0.1RCT015 1998 Short Rural 47 14 4 140 10 100.0 0 0 0.0% 1.0 2.1 0.0 0.0RCT021 1998 Short Rural 1 550 2 74,242 135 31.8% 159,256 290 68.2% 2.2 219.3 0.9 86.5RCT023 1998 Long Rural 439 2,594 9 175,882 68 45.8% 207,727 80 54.2% 1.6 0.4 0.5 0.1RobinvaleRVL001 1998 Long Rural 201 639 6 38,390 60 33.9% 74,834 117 66.1% 4.8 2.4 0.5 0.3RVL004 1998 Long Rural 273 368 6 11,743 32 19.4% 48,890 133 80.6% 4.8 1.7 0.8 0.3RVL006 1998 Short Rural 26 876 2 9,371 11 86.4% 1,475 2 13.6% 3.2 12.4 0.0 0.0RVL008 1998 Urban 13 549 0 84,441 154 77.5% 24,532 45 22.5% 6.1 47.0 0.1 1.0SheppartonSTN001 1998 Long Rural 354 1,033 3 216,816 210 79.4% 56,242 54 20.6% 6.2 1.7 0.4 0.1STN002 1998 Short Rural 55 2,916 8 115,308 40 51.4% 109,068 37 48.6% 3.1 5.7 0.1 0.2STN003 1998 Short Rural 132 761 3 165,490 217 99.2% 1,296 2 0.8% 2.0 1.5 0.1 0.0STN004 1998 Urban 19 2,686 0 155,007 58 93.2% 11,340 4 6.8% 7.3 38.4 0.0 0.1STN006 1998 Urban 5 426 0 12,850 30 100.0 0 0 0.0% 1.1 22.0 0.0 0.0STN007 1998 Urban 19 1,079 7 169,541 157 71.2% 68,415 63 28.8% 3.3 17.4 0.5 2.4STN008 1998 Urban 3 320 0 1,627 5 100.0 0 0 0.0% 1.2 41.5 0.0 0.0Shepparton


Doc No.71321 19/09/00 Page B 156



Cust.No

MVA

Total Percust

% oftotal

Total Percust

% oftotal

Total Per100km

Total Per100km

SHN011 1998 Short Rural 179 1,182 6 127,428 108 70.8% 52,681 45 29.2% 1.5 0.9 0.2 0.1SHN012 1998 Urban 11 2,281 0 7,840 3 68.1% 3,675 2 31.9% 1.1 10.2 0.0 0.1SHN014 1998 Urban 17 464 0 1,914 4 13.1% 12,677 27 86.9% 0.1 0.3 0.1 0.8SHN021 1998 Urban 2 1,343 0 299,640 223 80.4% 73,138 54 19.6% 8.1 405.3 0.2 8.7SHN022 1998 Urban 1 1,543 6 69,548 45 26.5% 192,875 125 73.5% 5.8 581.4 0.5 45.0SHN023 1998 Urban 20 802 7 3,389 4 100.0 0 0 0.0% 0.1 0.4 0.0 0.0SHN024 1998 Short Rural 175 939 4 132,506 141 97.7% 3,135 3 2.3% 8.6 4.9 0.1 0.0St AlbansSA001 1998 Urban 15 4,671 0 354,388 76 97.5% 9,120 2 2.5% 1.0 6.6 0.0 0.1SA002 1998 Urban 8 3,575 14 1,908,405 534 97.7% 44,360 12 2.3% 8.9 105.7 0.1 0.6SA003 1998 Urban 3 4,020 0 250,714 62 50.3% 247,515 62 49.7% 2.1 78.4 0.2 7.5SA004 1998 Urban 35 5,150 0 59,577 12 37.8% 98,100 19 62.2% 0.1 0.2 0.1 0.2SA005 1998 Urban 6 6,556 13 1,550,487 236 75.4% 505,882 77 24.6% 5.9 94.3 0.2 3.4SA006 1998 Urban 10 968 0 15,976 17 51.2% 15,230 16 48.8% 1.4 13.9 0.1 0.6SA007 1998 Urban 24 6,074 0 1,249,422 206 100.0 49 0 0.0% 3.8 15.6 0.0 0.0SA008 1998 Urban 14 923 9 220,491 239 100.0 0 0 0.0% 2.3 16.8 0.0 0.0StawellSTL004 1998 Short Rural 25 2,571 5 399,110 155 86.1% 64,655 25 13.9% 3.4 13.5 0.1 0.4STL005 1998 Long Rural 243 1,092 3 397,234 364 88.0% 53,945 49 12.0% 1.9 0.8 0.3 0.1STL006 1998 Long Rural 348 1,445 4 247,087 171 83.7% 47,992 33 16.3% 0.9 0.3 0.2 0.1STL007 1998 Long Rural 207 714 6 243,028 340 90.4% 25,781 36 9.6% 2.9 1.4 0.3 0.1SunshineS016 1998 Urban 1 2 0 232 116 19.0% 990 495 81.0% 1.0 100.0 3.0 300.0S019 1998 Urban 1 581 0 31,060 53 49.4% 31,800 55 50.6% 0.4 39.8 0.2 18.2S021 1998 Urban 1 5 0 50 10 10.2% 440 88 89.8% 0.4 40.0 0.4 40.0S022 1998 Urban 9 921 0 11,184 12 79.4% 2,899 3 20.6% 0.3 3.3 0.0 0.2S023 1998 Urban 1 38 0 7,276 191 100.0 0 0 0.0% 2.8 276.3 0.0 0.0SU001 1998 Urban 14 76 0 5,873 77 92.0% 510 7 8.0% 5.5 39.4 0.0 0.1SU002 1998 Urban 23 2,878 0 614,888 214 92.5% 49,708 17 7.5% 4.2 18.5 0.0 0.1SU003 1998 Urban 26 4,728 7 31,274 7 90.0% 3,475 1 10.0% 0.1 0.4 0.0 0.0SU004 1998 Urban 5 500 0 30,986 62 100.0 0 0 0.0% 0.4 8.4 0.0 0.0SU005 1998 Urban 46 493 11 498,380 1,011 99.3% 3,415 7 0.7% 20.2 43.8 0.0 0.1SU008 1998 Urban 27 3,118 0 155,866 50 90.7% 16,060 5 9.3% 5.2 19.4 0.0 0.1SU009 1998 Urban 25 2,262 0 164,860 73 42.2% 225,576 100 57.8% 2.3 9.1 0.3 1.3SU010 1998 Urban 8 1,270 0 198,371 156 99.9% 185 0 0.1% 2.5 31.1 0.0 0.0SU027 1998 Urban 1 464 5 128,706 277 100.0 0 0 0.0% 3.6 361.9 0.0 0.0SU097 1998 Urban 1 2,521 9 394,142 156 99.9% 345 0 0.1% 1.4 138.9 0.0 0.0Swan HillSHL001 1998 Long Rural 263 375 1 197,297 526 90.8% 19,959 53 9.2% 4.2 1.6 0.5 0.2SHL002 1998 Long Rural 406 1,482 5 280,929 190 84.2% 52,643 36 15.8% 1.6 0.4 0.3 0.1SHL004 1998 Long Rural 240 1,148 5 175,137 153 74.7% 59,420 52 25.3% 3.1 1.3 0.4 0.2SHL005 1998 Long Rural 341 1,220 4 998,820 819 97.1% 29,634 24 2.9% 5.0 1.5 0.1 0.0SHL007 1998 Urban 19 2,114 0 39,483 19 12.5% 275,886 131 87.5% 0.3 1.6 0.4 2.1SHL008 1998 Urban 8 2,100 0 43,554 21 59.2% 30,030 14 40.8% 0.2 2.5 0.0 0.5TerangTRG001 1998 Short Rural 148 581 8 154,837 267 86.4% 24,348 42 13.6% 2.7 1.8 0.1 0.1TRG002 1998 Long Rural 505 2,055 5 1,455,154 708 93.6% 99,364 48 6.4% 11.3 2.2 0.4 0.1


Doc No.71321 19/09/00 Page B 157



Cust.No

MVA

Total Percust

% oftotal

Total Percust

% oftotal

Total Per100km

Total Per100km

TRG003 1998 Long Rural 363 1,085 7 981,508 905 84.7% 177,429 164 15.3% 11.7 3.2 0.5 0.1TRG004 1998 Short Rural 14 1,041 3 246,603 237 98.0% 4,995 5 2.0% 4.9 35.3 0.1 0.9TRG005 1998 Long Rural 417 2,479 9 499,541 202 78.7% 135,330 55 21.3% 6.3 1.5 0.3 0.1WarnamboolWBL001 1998 Urban 13 1,960 0 146,631 75 80.6% 35,231 18 19.4% 2.7 20.7 0.1 0.5WBL002 1998 Short Rural 25 1,982 7 20,947 11 11.8% 156,905 79 88.2% 1.2 4.7 0.3 1.2WBL003 1998 Long Rural 275 426 6 8,446 20 10.2% 74,482 175 89.8% 1.2 0.4 0.6 0.2WBL004 1998 Short Rural 28 1,412 6 299,937 212 88.1% 40,449 29 11.9% 7.8 27.8 0.1 0.3WBL005 1998 Short Rural 108 853 2 106,011 124 73.6% 38,015 45 26.4% 2.6 2.4 0.1 0.1WBL007 1998 Short Rural 28 2,993 7 534,682 179 90.1% 58,715 20 9.9% 9.4 33.4 0.1 0.4WBL008 1998 Short Rural 38 1,853 5 82,739 45 100.0 9 0 0.0% 1.7 4.5 0.0 0.0WBL010 1998 Urban 10 1,185 0 22,763 19 56.4% 17,585 15 43.6% 1.3 12.7 0.1 1.2Waurn PondsWPD011 1998 Short Rural 149 386 1 13,332 35 15.3% 73,741 191 84.7% 1.1 0.8 0.7 0.5WPD014 1998 Long Rural 220 2,937 8 1,146,678 390 98.0% 23,873 8 2.0% 10.9 4.9 0.1 0.1WPD021 1998 Urban 6 3 0 0 0 0 0 0.0 0.0 0.7 11.1WPD022 1998 Short Rural 86 3,451 8 1,600,101 464 97.4% 42,491 12 2.6% 8.8 10.2 0.1 0.1WPD024 1998 Short Rural 32 3,397 8 390,670 115 54.4% 327,388 96 45.6% 4.7 14.6 0.3 1.0WPD031 1998 Short Rural 25 1,840 6 6,708 4 75.5% 2,178 1 24.5% 0.0 0.1 0.0 0.0WPD033 1998 Urban 14 1,035 0 78,794 76 82.0% 17,325 17 18.0% 1.4 10.0 0.1 0.4WerribeeWBE031 1998 Urban 28 4,515 7 22,392 5 97.5% 570 0 2.5% 2.1 7.6 0.0 0.0WBE032 1998 Short Rural 74 5,276 10 147,252 28 56.4% 113,900 22 43.6% 4.3 5.8 0.0 0.1WBE033 1998 Urban 48 3,339 10 732,280 219 98.9% 8,240 2 1.1% 4.3 9.0 0.0 0.0WBE034 1998 Urban 18 2,957 0 262,508 89 89.2% 31,630 11 10.8% 3.4 19.1 0.1 0.6WinchelseaWIN011 1998 Short Rural 76 620 2 205,696 332 61.1% 130,840 211 38.9% 5.3 7.0 0.6 0.8WIN012 1998 Long Rural 432 1,422 4 1,159,152 815 88.4% 151,472 107 11.6% 14.7 3.4 0.4 0.1WIN013 1998 Short Rural 77 503 2 195,806 389 86.2% 31,256 62 13.8% 5.5 7.2 0.4 0.5WoodendWND011 1998 Short Rural 170 1,890 6 155,809 82 86.8% 23,750 13 13.2% 1.2 0.7 0.0 0.0WND012 1998 Short Rural 79 3,073 10 1,069,483 348 84.3% 199,412 65 15.7% 3.9 4.9 0.3 0.4WND013 1998 Long Rural 434 3,602 8 2,625,617 729 95.4% 126,852 35 4.6% 4.7 1.1 0.2 0.1WND014 1998 Short Rural 56 1,976 7 131,951 67 76.6% 40,200 20 23.4% 1.5 2.7 0.1 0.1WND022 1998 Long Rural 283 2,343 9 343,395 147 71.6% 136,449 58 28.4% 2.7 0.9 0.3 0.1WND023 1998 Long Rural 342 1,679 4 442,301 263 93.1% 32,654 19 6.9% 2.1 0.6 0.2 0.1WND024 1998 Long Rural 209 1,749 4 1,318,289 754 79.2% 345,462 198 20.8% 3.2 1.5 0.7 0.4AaratART023 1999 Long Rural 206 939 3 4,242 5 36.0% 7,541 8 64.0% 1.9 0.9 0.0 0.0ART031 1999 Short Rural 84 1,193 2 9,550 8 98.4% 160 0 1.6% 3.2 3.8 0.0 0.0ART033 1999 Long Rural 897 1,983 3 633,326 319 84.2% 118,549 60 15.8% 7.8 0.9 0.3 0.0ART034 1999 Short Rural 20 1,855 3 128,558 69 77.8% 36,595 20 22.2% 3.5 17.3 0.2 0.8AltonaAL002 1999 Urban 14 1,436 5 197,044 137 99.4% 1,105 1 0.6% 4.3 30.9 0.0 0.0AL006 1999 Urban 1 2 5 0 0 0 0 1.0 88.8 0.0 0.0AL007 1999 Urban 10 1,808 5 62,590 35 96.1% 2,555 1 3.9% 1.2 11.6 0.0 0.0AL011 1999 Urban 2 14 2 0 0 0 0 1.3 71.0 0.0 0.0


Doc No.71321 19/09/00 Page B 158



Cust.No

MVA

Total Percust

% oftotal

Total Percust

% oftotal

Total Per100km

Total Per100km

AL012 1999 Urban 11 2,639 6 23,561 9 46.2% 27,450 10 53.8% 1.1 9.9 0.0 0.4AL014 1999 Urban 4 1 -9 0 0 0 0 1.0 25.6 0.0 0.0

AltonaAC024 1999 Urban 1 4 6 54 14 5.8% 880 220 94.2% 0.3 17.2 0.5 34.4AC031 1999 Urban 2 3 4 190 63 100.0 0 0 0.0% 0.7 37.5 0.0 0.0Bacchus MarshBMH003 1999 Long Rural 313 3,447 6 599,262 174 92.0% 52,028 15 8.0% 12.5 4.0 0.1 0.0BMH004 1999 Short Rural 33 2,940 7 355,217 121 80.4% 86,600 29 19.6% 11.7 35.1 0.2 0.5BMH005 1999 Short Rural 35 105 0 25,752 245 98.1% 497 5 1.9% 9.1 26.4 1.1 3.1BMH006 1999 Long Rural 206 971 5 232,431 239 97.7% 5,574 6 2.3% 10.3 5.0 0.0 0.0Ballarat NorthBAN001 1999 Urban 23 2,866 8 350,923 122 80.4% 85,728 30 19.6% 8.3 36.0 0.1 0.5BAN002 1999 Urban 17 813 9 61,765 76 99.4% 370 0 0.6% 6.3 36.2 0.0 0.0BAN003 1999 Urban 11 420 12 31,288 74 100.0 0 0 0.0% 4.5 42.3 0.0 0.0BAN004 1999 Urban 9 663 8 934 1 87.6% 132 0 12.4% 0.0 0.2 0.0 0.0BAN005 1999 Urban 9 1,451 3 10,322 7 45.6% 12,290 8 54.4% 3.1 34.4 0.1 0.8BAN006 1999 Long Rural 392 4,535 9 301,602 67 86.3% 47,937 11 13.7% 6.7 1.7 0.1 0.0BAN007 1999 Short Rural 34 3,814 6 873,679 229 99.1% 8,305 2 0.9% 4.3 12.6 0.0 0.0BAN008 1999 Long Rural 372 4,164 10 4,459,758 1,071 97.9% 97,560 23 2.1% 7.5 2.0 0.1 0.0BAN009 1999 Long Rural 339 2,552 8 401,250 157 78.0% 112,969 44 22.0% 10.0 3.0 0.2 0.1BAN011 1999 Long Rural 443 1,849 5 1,168,950 632 96.0% 49,123 27 4.0% 9.2 2.1 0.2 0.0BAN013 1999 Urban 7 494 9 2,593 5 14.6% 15,153 31 85.4% 0.1 1.2 0.1 2.2BAN015 1999 Short Rural 51 3,492 7 246,193 71 96.0% 10,300 3 4.0% 5.3 10.5 0.0 0.0Ballarat SouthBAS011 1999 Long Rural 943 3,115 10 600,829 193 97.3% 16,580 5 2.7% 1.2 0.1 0.1 0.0BAS012 1999 Urban 9 2,159 7 19,677 9 82.6% 4,140 2 17.4% 0.1 0.8 0.1 0.6BAS013 1999 Short Rural 22 1,931 3 15,402 8 63.5% 8,835 5 36.5% 1.1 5.1 0.0 0.1BAS014 1999 Urban 15 2,894 7 46,497 16 94.8% 2,530 1 5.2% 2.2 14.8 0.0 0.0BAS021 1999 Long Rural 522 3,807 6 984,432 259 88.4% 128,768 34 11.6% 4.9 0.9 0.2 0.0BAS022 1999 Long Rural 488 4,496 8 800,525 178 85.8% 132,265 29 14.2% 10.9 2.2 0.2 0.0BAS023 1999 Short Rural 59 2,895 4 632,810 219 99.3% 4,430 2 0.7% 4.2 7.1 0.0 0.0BAS024 1999 Urban 3 103 6 194 2 100.0 0 0 0.0% 0.0 0.3 0.0 0.0BAS034 1999 Short Rural 29 3,070 7 458,440 149 98.9% 4,883 2 1.1% 3.3 11.2 0.1 0.3BendigoBGO011 1999 Urban 4 683 10 193,342 283 99.9% 210 0 0.1% 3.2 80.2 0.0 0.1BGO012 1999 Short Rural 94 3,958 8 114,498 29 67.9% 54,074 14 32.1% 0.4 0.4 0.1 0.2BGO013 1999 Long Rural 531 4,259 11 198,093 47 49.8% 199,899 47 50.2% 0.5 0.1 0.2 0.0BGO021 1999 Urban 11 1,203 8 147,814 123 56.4% 114,194 95 43.6% 1.9 16.6 0.3 2.9BGO022 1999 Long Rural 314 4,571 9 107,643 24 38.4% 172,517 38 61.6% 1.5 0.5 0.2 0.1BGO023 1999 Urban 13 950 9 41,121 43 30.0% 96,066 101 70.0% 1.2 9.7 0.4 2.8BendigoBET001 1999 Short Rural 28 1,966 6 475,048 242 91.1% 46,430 24 8.9% 3.1 11.1 0.1 0.4BET002 1999 Short Rural 100 4,353 9 442,688 102 93.2% 32,050 7 6.8% 1.1 1.1 0.1 0.1BET003 1999 Urban 11 313 7 23,020 74 33.4% 45,995 147 66.6% 2.6 24.2 0.6 5.2BET004 1999 Short Rural 97 2,185 6 27,730 13 5.1% 517,471 237 94.9% 0.2 0.2 0.8 0.8BrooklynBLT016 1999 Urban 1 94 10 9,248 98 64.8% 5,017 53 35.2% 6.8 526.2 0.3 26.2


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Cust.No

MVA

Total Percust

% oftotal

Total Percust

% oftotal

Total Per100km

Total Per100km

BLT017 1999 Urban 9 802 10 8,499 11 77.8% 2,425 3 22.2% 0.1 1.1 0.0 0.1BLT020 1999 Urban 12 64 11 19,453 304 98.2% 360 6 1.8% 10.0 80.6 0.0 0.4BLT021 1999 Urban 1 1 8 0 0 0.0% 290 290 100.0 0.0 0.0 1.0 110.0BLT022 1999 Urban 7 1,590 7 21,905 14 51.9% 20,321 13 48.1% 0.1 2.1 0.1 1.1BLT030 1999 Urban 10 1,864 6 127,377 68 82.4% 27,158 15 17.6% 2.3 22.7 0.1 0.6BLT031 1999 Urban 10 1,187 9 5,332 4 100.0 0 0 0.0% 0.1 0.5 0.0 0.0CamperdownCDN001 1999 Long Rural 283 1,688 9 690,889 409 76.0% 217,764 129 24.0% 6.0 2.1 0.5 0.2CDN002 1999 Short Rural 184 532 3 339,652 638 100.0 150 0 0.0% 5.3 2.9 0.0 0.0CDN003 1999 Urban 15 1,543 6 39,485 26 100.0 0 0 0.0% 0.2 1.5 0.0 0.0CDN004 1999 Long Rural 380 806 3 525,486 652 98.0% 10,960 14 2.0% 3.7 1.0 0.1 0.0CDN006 1999 Long Rural 425 1,018 4 383,570 377 89.3% 46,050 45 10.7% 1.5 0.3 0.1 0.0CastlemaineCMN001 1999 Short Rural 117 1,345 2 9,258 7 23.3% 30,410 23 76.7% 0.1 0.0 0.1 0.1CMN002 1999 Long Rural 335 2,386 4 456,673 191 89.9% 51,348 22 10.1% 6.6 2.0 0.1 0.0CMN003 1999 Long Rural 259 2,547 5 182,720 72 94.6% 10,499 4 5.4% 2.4 0.9 0.0 0.0CMN004 1999 Short Rural 198 1,335 3 190,290 143 47.1% 213,664 160 52.9% 1.8 0.9 0.6 0.3CMN005 1999 Urban 18 968 7 29,549 31 97.9% 645 1 2.1% 1.3 7.2 0.0 0.0CharltonCTN001 1999 Long Rural 825 1,739 4 509,256 293 89.2% 61,475 35 10.8% 6.6 0.8 0.1 0.0CTN002 1999 Long Rural 503 1,186 2 59,892 50 77.5% 17,372 15 22.5% 2.1 0.4 0.2 0.0CTN003 1999 Long Rural 675 1,396 3 470,985 337 96.7% 16,262 12 3.3% 4.1 0.6 0.2 0.0CTN004 1999 Long Rural 221 1,153 4 257,340 223 78.2% 71,715 62 21.8% 4.6 2.1 0.5 0.2CTN005 1999 Urban 7 617 2 133,676 217 88.5% 17,440 28 11.5% 5.4 73.4 0.2 2.4CTN006 1999 Long Rural 976 2,094 5 248,790 119 63.9% 140,252 67 36.1% 6.7 0.7 0.3 0.0Cobram EastCME014 1999 Short Rural 88 2,016 8 347,862 173 71.6% 138,194 69 28.4% 10.4 11.8 0.2 0.3CME015 1999 Urban 26 613 11 78,004 127 89.2% 9,405 15 10.8% 8.9 34.4 0.1 0.4CME016 1999 Long Rural 302 1,768 7 1,545,420 874 87.1% 229,719 130 12.9% 28.8 9.6 0.6 0.2CME021 1999 Urban 26 1,466 9 184,680 126 97.8% 4,082 3 2.2% 4.6 17.7 0.1 0.5CME022 1999 Short Rural 83 829 6 294,200 355 89.2% 35,540 43 10.8% 11.9 14.4 0.2 0.3CohunaCHA003 1999 Short Rural 104 1,224 4 88,755 73 95.7% 3,950 3 4.3% 9.1 8.7 0.0 0.0CHA005 1999 Long Rural 247 1,216 7 154,265 127 80.3% 37,768 31 19.7% 11.3 4.6 0.3 0.1CHA006 1999 Long Rural 546 1,508 6 258,219 171 76.7% 78,442 52 23.3% 6.0 1.1 0.2 0.0ColacCLC001 1999 Urban 11 1,842 4 15,976 9 100.0 0 0 0.0% 0.1 1.1 0.0 0.0CLC002 1999 Urban 12 2,350 8 6,085 3 17.1% 29,438 13 82.9% 0.0 0.2 0.1 0.7CLC003 1999 Long Rural 531 1,526 8 370,504 243 77.2% 109,419 72 22.8% 4.1 0.8 0.7 0.1CLC004 1999 Long Rural 215 1,251 6 149,762 120 42.4% 203,474 163 57.6% 1.3 0.6 0.6 0.3CLC005 1999 Short Rural 67 1,752 5 201,532 115 85.1% 35,270 20 14.9% 1.7 2.5 0.1 0.1CLC006 1999 Long Rural 292 2,734 7 858,085 314 90.9% 85,630 31 9.1% 4.2 1.4 0.2 0.1CLC008 1999 Long Rural 279 2,649 7 886,842 335 86.7% 135,855 51 13.3% 5.4 1.9 0.3 0.1CorioCRO013 1999 Short Rural 181 3,855 5 382,763 99 43.5% 496,466 129 56.5% 2.7 1.5 0.4 0.2CRO021 1999 Urban 7 658 6 79,326 121 86.9% 12,001 18 13.1% 1.8 26.1 0.2 2.4


Doc No.71321 19/09/00 Page B 160



Cust.No

MVA

Total Percust

% oftotal

Total Percust

% oftotal

Total Per100km

Total Per100km

CRO022 1999 Urban 18 3,380 8 170,337 50 93.5% 11,883 4 6.5% 1.5 8.0 0.0 0.1CRO023 1999 Short Rural 4 249 1 2,964 12 88.4% 390 2 11.6% 1.1 28.4 0.0 0.1CRO033 1999 Urban 2 19 2 1,088 57 100.0 0 0 0.0% 0.4 18.7 0.0 0.0CRO034 1999 Urban 7 1,300 5 130,896 101 96.6% 4,600 4 3.4% 1.1 17.2 0.1 1.2DrysdaleDDL011 1999 Short Rural 25 2,939 4 318,024 108 99.4% 1,855 1 0.6% 4.7 19.0 0.0 0.0DDL012 1999 Short Rural 49 3,345 6 112,290 34 97.8% 2,528 1 2.2% 1.4 2.8 0.0 0.0DDL013 1999 Short Rural 65 2,913 5 197,880 68 87.8% 27,430 9 12.2% 0.5 0.8 0.0 0.1DDL014 1999 Urban 21 2,679 7 108,594 41 85.4% 18,570 7 14.6% 5.0 23.6 0.1 0.2DDL022 1999 Short Rural 64 2,977 6 121,526 41 84.4% 22,395 8 15.6% 0.2 0.2 0.0 0.1DDL023 1999 Short Rural 93 3,539 9 2,038,752 576 94.8% 111,869 32 5.2% 14.0 15.1 0.1 0.1DDL024 1999 Short Rural 57 1,678 3 44,630 27 81.5% 10,161 6 18.5% 3.2 5.6 0.0 0.0EaglehawkEHK021 1999 Urban 14 417 8 114,842 275 65.3% 61,125 147 34.7% 0.9 6.5 0.5 3.5EHK022 1999 Long Rural 507 4,006 9 1,636,875 409 92.6% 130,774 33 7.4% 8.5 1.7 0.2 0.0EHK023 1999 Short Rural 16 578 4 2,563 4 100.0 0 0 0.0% 0.1 0.3 0.0 0.0EHK024 1999 Long Rural 1263 3,400 12 1,072,335 315 97.0% 33,515 10 3.0% 3.0 0.2 0.1 0.0EHK031 1999 Short Rural 68 3,569 7 355,088 99 69.7% 154,421 43 30.3% 1.2 1.8 0.2 0.3EHK032 1999 Short Rural 154 1,835 4 316,505 172 61.2% 200,301 109 38.8% 2.0 1.3 0.6 0.4EHK033 1999 Urban 9 2,247 4 22,641 10 19.8% 91,439 41 80.2% 0.1 1.6 0.2 1.7EHK034 1999 Urban 7 1,032 7 30,217 29 43.3% 39,560 38 56.7% 0.4 5.6 0.2 2.5EchucaECA001 1999 Urban 18 2,068 9 55,075 27 87.1% 8,165 4 12.9% 5.4 30.8 0.0 0.3ECA003 1999 Short Rural 64 2,415 10 51,300 21 60.6% 33,290 14 39.4% 4.4 7.0 1.2 1.8ECA005 1999 Long Rural 273 632 6 11,562 18 51.4% 10,924 17 48.6% 4.5 1.6 0.2 0.1ECA007 1999 Long Rural 332 1,104 11 191,852 174 75.9% 60,852 55 24.1% 5.9 1.8 0.3 0.1ECA010 1999 Long Rural 319 1,911 7 353,943 185 76.4% 109,311 57 23.6% 14.5 4.6 0.3 0.1ECA012 1999 Long Rural 331 2,102 8 318,994 152 79.4% 82,865 39 20.6% 4.3 1.3 0.2 0.1Ford NorthFNS011 1999 Short Rural 99 2,698 9 178,823 66 91.9% 15,695 6 8.1% 0.5 0.5 0.0 0.0FNS012 1999 Short Rural 57 3,623 7 740,164 204 74.2% 257,025 71 25.8% 5.5 9.6 0.3 0.5FNS021 1999 Short Rural 14 775 3 122,631 158 99.4% 732 1 0.6% 2.2 15.8 0.0 0.0FNS022 1999 Short Rural 112 558 7 257,461 461 93.3% 18,575 33 6.7% 9.7 8.6 0.2 0.2FNS032 1999 Short Rural 44 236 3 323,055 1,369 94.7% 18,120 77 5.3% 13.0 30.0 0.5 1.3GeelongGL011 1999 Urban 10 1,520 4 79,635 52 60.7% 51,665 34 39.3% 4.4 44.8 0.2 1.8GL012 1999 Urban 6 1,104 2 6,184 6 7.0% 82,331 75 93.0% 0.1 1.1 0.2 4.2GL013 1999 Short Rural 10 2,377 3 224,356 94 86.3% 35,490 15 13.7% 1.1 10.5 0.1 1.0GL014 1999 Long Rural 211 3,105 6 109,374 35 86.0% 17,758 6 14.0% 3.5 1.7 0.0 0.0GL015 1999 Urban 3 313 2 15,504 50 100.0 0 0 0.0% 0.7 24.1 0.0 0.0GL021 1999 Short Rural 29 5,608 9 475,799 85 79.7% 121,431 22 20.3% 2.4 8.0 0.1 0.4GL022 1999 Urban 10 3,468 5 934,233 269 97.8% 20,895 6 2.2% 3.1 30.6 0.0 0.3GL023 1999 Urban 7 1,040 3 27,229 26 100.0 0 0 0.0% 1.1 16.5 0.0 0.0GL024 1999 Long Rural 372 4,066 9 834,548 205 88.7% 106,482 26 11.3% 2.5 0.7 0.1 0.0Geelong BGB011 1999 Urban 2 7 4 284 41 100.0 0 0 0.0% 0.6 26.9 0.0 0.0


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Cust.No

MVA

Total Percust

% oftotal

Total Percust

% oftotal

Total Per100km

Total Per100km

GB012 1999 Urban 4 10 4 0 0 0.0% 1,712 171 100.0 0.0 0.0 0.7 18.5GB031 1999 Urban 7 216 6 12,965 60 27.8% 33,607 156 72.2% 2.3 31.0 1.0 13.4GB032 1999 Urban 1 3 6 0 0 0.0% 586 195 100.0 0.0 0.0 0.7 49.8Geelong CityGCY012 1999 Urban 3 88 9 14,717 167 17.4% 69,677 792 82.6% 1.9 60.3 1.4 43.7GCY013 1999 Urban 2 441 6 4,831 11 57.7% 3,544 8 42.3% 0.1 4.3 0.1 4.3GCY014 1999 Urban 20 3,295 8 75,181 23 85.3% 12,910 4 14.7% 2.2 11.4 0.0 0.1GCY021 1999 Urban 2 263 4 6,161 23 33.6% 12,160 46 66.4% 0.2 8.1 0.1 6.2GCY022 1999 Urban 3 438 5 8,171 19 100.0 0 0 0.0% 0.2 9.2 0.0 0.0GCY023 1999 Urban 16 3,250 9 92,973 29 87.6% 13,215 4 12.4% 0.3 2.0 0.1 0.3GCY024 1999 Urban 9 2,070 6 23,251 11 38.9% 36,490 18 61.1% 2.2 25.6 0.1 1.0Geelong EastGLE011 1999 Urban 5 233 5 4,223 18 46.9% 4,778 21 53.1% 1.3 23.2 0.1 2.2GLE012 1999 Urban 20 3,523 7 423,150 120 94.3% 25,695 7 5.7% 3.5 17.3 0.1 0.4GLE013 1999 Short Rural 42 3,913 6 376,247 96 84.5% 68,825 18 15.5% 2.1 4.9 0.1 0.2GLE021 1999 Urban 4 437 5 7,140 16 34.8% 13,350 31 65.2% 0.3 6.1 0.1 1.6GLE024 1999 Short Rural 65 5,001 8 293,064 59 75.8% 93,410 19 24.2% 2.2 3.4 0.1 0.1GLE031 1999 Short Rural 42 2,595 8 51,713 20 65.8% 26,840 10 34.2% 3.2 7.6 0.0 0.1GLE032 1999 Urban 12 2,584 4 264,729 102 99.8% 475 0 0.2% 1.1 9.3 0.0 0.0GLE033 1999 Urban 7 426 4 9,995 23 37.0% 16,995 40 63.0% 1.1 15.4 0.2 3.0HamiltonHTN001 1999 Long Rural 302 834 2 382,856 459 98.0% 7,660 9 2.0% 3.9 1.3 0.0 0.0HTN002 1999 Long Rural 1250 2,170 3 724,409 334 94.2% 44,634 21 5.8% 2.7 0.2 0.1 0.0HTN003 1999 Long Rural 512 1,770 4 230,095 130 98.2% 4,250 2 1.8% 3.5 0.7 0.0 0.0HTN004 1999 Long Rural 366 3,010 6 193,469 64 98.2% 3,470 1 1.8% 4.8 1.3 0.1 0.0HTN005 1999 Long Rural 435 2,699 6 886,419 328 92.2% 74,924 28 7.8% 6.2 1.4 0.1 0.0HTN006 1999 Long Rural 571 2,477 6 1,219,437 492 95.7% 54,635 22 4.3% 5.0 0.9 0.2 0.0HorshamHSM001 1999 Long Rural 1247 2,225 5 1,019,211 458 99.2% 8,130 4 0.8% 2.7 0.2 0.1 0.0HSM002 1999 Long Rural 1524 2,928 4 605,527 207 93.5% 42,029 14 6.5% 2.6 0.2 0.2 0.0HSM003 1999 Long Rural 576 1,488 4 276,263 186 91.9% 24,510 16 8.1% 2.4 0.4 0.0 0.0HSM004 1999 Long Rural 1060 1,972 4 553,016 280 64.7% 301,842 153 35.3% 3.9 0.4 0.6 0.1HSM005 1999 Long Rural 367 1,514 4 65,784 43 87.5% 9,415 6 12.5% 0.2 0.1 0.1 0.0HSM006 1999 Long Rural 282 2,090 5 78,033 37 58.2% 55,986 27 41.8% 0.2 0.1 0.2 0.1HSM009 1999 Urban 19 2,376 8 17,584 7 26.9% 47,820 20 73.1% 0.1 0.4 0.1 0.6HSM010 1999 Urban 23 3,086 9 48,725 16 56.6% 37,390 12 43.4% 1.2 5.2 0.1 0.4KerangKGT002 1999 Short Rural 53 2,044 6 887,742 434 96.2% 34,932 17 3.8% 7.6 14.3 0.1 0.2KGT003 1999 Long Rural 356 1,147 4 404,706 353 88.8% 50,903 44 11.2% 3.4 1.0 0.2 0.1KGT004 1999 Long Rural 475 786 2 196,798 250 83.6% 38,710 49 16.4% 5.8 1.2 0.4 0.1KoroitKRT012 1999 Long Rural 280 846 2 54,459 64 59.6% 36,977 44 40.4% 6.8 2.4 0.2 0.1KRT013 1999 Long Rural 424 1,703 5 354,810 208 95.3% 17,347 10 4.7% 6.5 1.5 0.1 0.0KRT021 1999 Short Rural 33 148 6 38,385 259 84.5% 7,020 47 15.5% 6.3 19.0 0.2 0.5KRT022 1999 Short Rural 192 2,427 6 806,940 332 73.3% 293,576 121 26.7% 10.8 5.6 0.6 0.3KRT023 1999 Short Rural 37 1,374 8 335,493 244 92.1% 28,736 21 7.9% 7.4 20.1 0.2 0.5


Doc No.71321 19/09/00 Page B 162



Cust.No

MVA

Total Percust

% oftotal

Total Percust

% oftotal

Total Per100km

Total Per100km

KyabramKYM001 1999 Long Rural 280 1,180 11 282,249 239 76.6% 86,136 73 23.4% 5.4 1.9 0.3 0.1KYM002 1999 Long Rural 312 1,649 12 426,334 259 73.7% 152,330 92 26.3% 2.9 0.9 0.3 0.1KYM003 1999 Long Rural 261 1,498 7 210,629 141 81.8% 46,760 31 18.2% 4.8 1.8 0.2 0.1KYM004 1999 Short Rural 194 1,489 5 416,147 279 87.2% 61,065 41 12.8% 6.4 3.3 0.2 0.1KYM005 1999 Urban 20 2,518 9 57,038 23 61.8% 35,246 14 38.2% 0.2 1.1 0.1 0.3KYM006 1999 Short Rural 82 414 10 32,388 78 47.8% 35,364 85 52.2% 1.7 2.0 0.4 0.5LavertonLV001 1999 Short Rural 107 2,798 12 567,836 203 93.3% 40,726 15 6.7% 5.0 4.7 0.1 0.1LV002 1999 Urban 23 135 13 57,002 422 81.7% 12,799 95 18.3% 5.6 24.1 0.2 1.0LV003 1999 Urban 12 26 12 6,049 233 93.9% 390 15 6.1% 5.2 42.3 0.0 0.3LV004 1999 Urban 26 3,499 12 1,070,804 306 99.7% 3,290 1 0.3% 9.6 36.3 0.0 0.0LV005 1999 Urban 13 645 10 109,385 170 99.8% 200 0 0.2% 2.4 18.6 0.0 0.0LV006 1999 Urban 38 4,852 14 381,343 79 100.0 0 0 0.0% 2.9 7.7 0.0 0.0LV007 1999 Urban 16 2,293 14 62,232 27 100.0 0 0 0.0% 2.0 12.3 0.0 0.0LV008 1999 Short Rural 50 3,269 10 1,064,618 326 97.7% 24,780 8 2.3% 8.0 16.0 0.0 0.1LV009 1999 Urban 23 4,311 10 611,801 142 96.9% 19,275 4 3.1% 3.2 13.8 0.0 0.1MaryboroughMRO004 1999 Short Rural 18 1,995 4 165,536 83 81.1% 38,675 19 18.9% 2.2 12.2 0.1 0.4MRO005 1999 Long Rural 511 1,724 4 330,135 191 76.3% 102,784 60 23.7% 2.7 0.5 0.2 0.0MRO006 1999 Urban 4 622 3 58,555 94 89.1% 7,139 11 10.9% 1.1 31.2 0.2 5.4MRO007 1999 Long Rural 484 1,640 4 296,228 181 73.4% 107,219 65 26.6% 6.7 1.4 0.5 0.1MRO008 1999 Long Rural 282 2,348 6 183,922 78 88.9% 22,985 10 11.1% 0.6 0.2 0.0 0.0MeltonMLN011 1999 Short Rural 81 4,985 11 361,506 73 65.5% 190,767 38 34.5% 3.6 4.4 0.1 0.2MLN012 1999 Short Rural 117 3,846 9 146,487 38 48.9% 152,983 40 51.1% 1.3 1.1 0.2 0.2MLN021 1999 Short Rural 85 808 8 450,570 558 99.2% 3,735 5 0.8% 8.3 9.8 0.0 0.0MLN024 1999 Short Rural 40 3,215 10 402,853 125 99.1% 3,850 1 0.9% 2.4 5.9 0.0 0.0MerbeinMBN012 1999 Short Rural 33 1,903 9 20,824 11 26.9% 56,600 30 73.1% 0.1 0.3 0.2 0.5MBN013 1999 Short Rural 39 444 3 11,241 25 12.8% 76,534 172 87.2% 0.3 0.7 0.7 1.9MBN014 1999 Short Rural 78 707 4 103,161 146 73.5% 37,265 53 26.5% 1.7 2.1 0.2 0.3MBN021 1999 Short Rural 126 1,181 4 149,522 127 44.0% 190,136 161 56.0% 0.6 0.5 0.7 0.6MBN022 1999 Short Rural 45 1,342 5 66,109 49 45.0% 80,944 60 55.0% 0.4 0.9 0.2 0.5MilduraMDA022 1999 Urban 11 2,507 13 50,806 20 42.1% 69,962 28 57.9% 0.2 2.2 0.2 1.5MDA023 1999 Short Rural 83 1,645 7 663,510 403 92.6% 52,858 32 7.4% 3.0 3.6 0.1 0.1MDA024 1999 Short Rural 26 603 7 45,896 76 49.0% 47,787 79 51.0% 1.3 5.1 0.8 3.1MDA031 1999 Urban 13 1,262 7 79,469 63 46.0% 93,200 74 54.0% 2.2 17.3 0.5 4.1MDA032 1999 Urban 14 2,462 11 60,784 25 58.1% 43,753 18 41.9% 0.1 0.8 0.1 0.7MDA033 1999 Urban 24 1,691 8 104,487 62 77.0% 31,171 18 23.0% 2.0 8.6 0.1 0.2MooroopnaMNA014 1999 Long Rural 300 2,030 9 1,182,885 583 76.1% 372,422 183 23.9% 18.1 6.0 0.6 0.2MNA021 1999 Short Rural 79 1,938 12 227,763 118 56.1% 178,118 92 43.9% 12.7 16.1 0.3 0.4MNA022 1999 Urban 5 412 7 20,970 51 94.1% 1,325 3 5.9% 0.3 6.9 0.0 0.2MNA024 1999 Urban 15 1,089 6 77,879 72 42.9% 103,765 95 57.1% 1.7 11.3 0.3 2.0


Doc No.71321 19/09/00 Page B 163



Cust.No

MVA

Total Percust

% oftotal

Total Percust

% oftotal

Total Per100km

Total Per100km

MNA034 1999 Long Rural 320 1,907 6 533,971 280 83.2% 107,500 56 16.8% 13.7 4.3 0.2 0.1NhillNHL015 1999 Long Rural 625 1,767 3 220,476 125 70.0% 94,481 53 30.0% 4.4 0.7 0.2 0.0NHL016 1999 Long Rural 290 1,399 3 19,972 14 33.7% 39,250 28 66.3% 3.2 1.1 0.2 0.1NHL031 1999 Long Rural 899 1,439 2 464,143 323 94.2% 28,389 20 5.8% 14.6 1.6 0.2 0.0NurmukaNKA001 1999 Long Rural 328 1,086 4 160,933 148 26.2% 453,229 417 73.8% 6.4 2.0 1.4 0.4NKA002 1999 Long Rural 458 2,153 8 455,834 212 86.9% 68,675 32 13.1% 7.6 1.7 0.2 0.0NKA003 1999 Short Rural 52 466 6 91,686 197 96.3% 3,492 7 3.7% 6.5 12.6 0.1 0.1NKA004 1999 Short Rural 70 2,000 9 50,954 25 35.7% 91,677 46 64.3% 3.3 4.8 0.3 0.4NKA005 1999 Long Rural 230 783 4 358,902 458 65.2% 191,947 245 34.8% 7.5 3.3 1.2 0.5NKA006 1999 Short Rural 181 709 5 59,650 84 76.2% 18,583 26 23.8% 4.0 2.2 0.1 0.1OuyenOYN001 1999 Long Rural 886 1,036 2 128,492 124 94.1% 8,101 8 5.9% 5.9 0.7 0.1 0.0OYN003 1999 Long Rural 398 447 1 191,491 428 77.0% 57,166 128 23.0% 7.1 1.8 0.5 0.1OYN005 1999 Long Rural 1206 1,546 3 1,122,255 726 97.4% 30,322 20 2.6% 14.4 1.2 0.1 0.0OYN007 1999 Urban 9 637 3 3,200 5 74.5% 1,095 2 25.5% 2.1 24.1 0.0 0.1PortlandPLD001 1999 Long Rural 308 1,688 5 267,069 158 61.8% 165,048 98 38.2% 4.3 1.4 0.5 0.2PLD002 1999 Urban 4 12 2 123 10 100.0 0 0 0.0% 0.2 4.4 0.0 0.0PLD003 1999 Long Rural 490 1,144 6 233,683 204 96.5% 8,495 7 3.5% 1.8 0.4 0.0 0.0PLD004 1999 Short Rural 26 2,490 5 646,164 260 97.1% 19,090 8 2.9% 6.9 26.6 0.1 0.2PLD005 1999 Urban 10 163 6 21,749 133 87.1% 3,223 20 12.9% 3.3 32.3 0.1 0.6PLD006 1999 Short Rural 129 2,615 5 280,932 107 99.9% 170 0 0.1% 3.4 2.6 0.0 0.0Red CliffsRCT011 1999 Short Rural 38 639 2 13,965 22 68.4% 6,465 10 31.6% 1.3 3.4 0.1 0.1RCT013 1999 Long Rural 260 768 7 295,543 385 95.7% 13,252 17 4.3% 4.1 1.6 0.1 0.0RCT014 1999 Short Rural 91 851 11 20,567 24 19.7% 83,689 98 80.3% 2.2 2.4 0.3 0.4RCT015 1999 Urban 9 15 4 0 0 0.0% 200 13 100.0 0.0 0.0 0.1 0.8RCT021 1999 Short Rural 32 901 2 91,958 102 86.3% 14,556 16 13.7% 3.5 11.2 0.1 0.3RCT023 1999 Long Rural 598 2,457 9 468,256 191 51.0% 449,382 183 49.0% 2.2 0.4 0.7 0.1RobinvaleRVL001 1999 Long Rural 200 565 6 119,502 212 84.6% 21,766 39 15.4% 4.4 2.2 0.1 0.1RVL004 1999 Short Rural 46 501 6 114,791 229 77.7% 32,875 66 22.3% 5.3 11.7 0.2 0.5RVL006 1999 Short Rural 18 885 4 68,071 77 48.9% 71,275 81 51.1% 2.2 12.3 0.3 1.7RVL008 1999 Long Rural 218 427 5 67,648 158 43.7% 87,148 204 56.3% 3.5 1.6 0.9 0.4SheppartonSTN001 1999 Long Rural 276 1,016 5 186,071 183 57.7% 136,370 134 42.3% 9.1 3.3 0.5 0.2STN002 1999 Short Rural 37 3,044 9 146,534 48 50.8% 141,707 47 49.2% 2.1 5.7 0.2 0.6STN003 1999 Short Rural 40 782 3 76,783 98 18.7% 333,245 426 81.3% 4.2 10.3 2.2 5.4STN004 1999 Urban 14 2,686 7 82,782 31 78.5% 22,684 8 21.5% 0.3 2.0 0.1 0.6STN006 1999 Urban 3 427 4 6,353 15 35.8% 11,395 27 64.2% 1.8 53.2 0.1 2.9STN007 1999 Short Rural 200 1,083 6 99,279 92 67.1% 48,740 45 32.9% 2.3 1.1 0.2 0.1STN008 1999 Urban 3 320 6 67,646 211 100.0 19 0 0.0% 1.6 46.0 0.0 0.1SheppartonSHN011 1999 Long Rural 258 1,201 6 621,236 517 95.0% 32,632 27 5.0% 5.5 2.1 0.1 0.1


Doc No.71321 19/09/00 Page B 164



Cust.No

MVA

Total Percust

% oftotal

Total Percust

% oftotal

Total Per100km

Total Per100km

SHN012 1999 Urban 19 2,274 6 16,735 7 36.5% 29,115 13 63.5% 2.2 11.5 0.1 0.4SHN014 1999 Urban 16 423 8 54,002 128 91.7% 4,914 12 8.3% 6.3 38.7 0.1 0.6SHN021 1999 Short Rural 30 1,363 4 105,389 77 94.7% 5,910 4 5.3% 4.3 14.2 0.0 0.1SHN022 1999 Urban 9 1,473 6 53,301 36 58.1% 38,400 26 41.9% 2.1 23.6 0.1 0.9SHN023 1999 Urban 19 740 7 8,023 11 7.2% 102,700 139 92.8% 1.4 7.3 0.4 2.2SHN024 1999 Short Rural 141 967 4 28,707 30 23.0% 96,340 100 77.0% 2.2 1.6 0.3 0.2St AlbansSA001 1999 Urban 25 4,801 13 1,185,130 247 100.0 0 0 0.0% 6.2 25.3 0.0 0.0SA002 1999 Urban 30 3,199 10 1,217,515 381 96.7% 42,021 13 3.3% 7.8 26.4 0.1 0.2SA003 1999 Urban 17 3,966 10 39,351 10 71.6% 15,641 4 28.4% 0.1 0.7 0.0 0.2SA004 1999 Urban 29 5,365 9 429,578 80 86.8% 65,057 12 13.2% 2.1 7.5 0.0 0.1SA005 1999 Urban 33 5,279 20 1,588,776 301 92.6% 126,158 24 7.4% 25.1 76.4 0.1 0.4SA006 1999 Urban 9 2,568 8 520,302 203 85.7% 86,662 34 14.3% 4.0 44.0 0.1 1.1SA007 1999 Urban 20 5,326 11 589,064 111 99.2% 4,550 1 0.8% 6.5 32.0 0.0 0.0SA008 1999 Urban 11 943 9 296,925 315 99.9% 365 0 0.1% 4.0 36.3 0.0 0.0StawellSTL004 1999 Short Rural 20 2,556 5 206,606 81 96.2% 8,190 3 3.8% 3.6 17.6 0.0 0.1STL005 1999 Long Rural 317 1,116 3 735,532 659 91.3% 70,180 63 8.7% 6.2 1.9 0.2 0.1STL006 1999 Long Rural 607 1,439 2 113,618 79 89.7% 12,984 9 10.3% 2.5 0.4 0.1 0.0STL007 1999 Long Rural 320 727 6 23,334 32 44.1% 29,566 41 55.9% 2.5 0.8 0.2 0.1SunshineS016 1999 Urban 1 4 0 0 0 0 0 1.0 156.5 0.0 0.0S019 1999 Urban 3 566 2 3,475 6 100.0 0 0 0.0% 1.2 38.3 0.0 0.0S021 1999 Urban 0 4 0 0 0 0 0 1.3 668.0 0.0 0.0S022 1999 Urban 5 918 1 23,894 26 100.0 0 0 0.0% 1.2 26.6 0.0 0.0S023 1999 Urban 1 31 1 165 5 100.0 0 0 0.0% 1.4 116.2 0.0 0.0SU001 1999 Urban 12 78 20 491 6 79.1% 130 2 20.9% 3.5 29.0 0.0 0.1SU002 1999 Urban 23 2,934 24 753,195 257 100.0 0 0 0.0% 5.2 22.8 0.0 0.0SU003 1999 Urban 31 5,926 13 916,513 155 97.6% 22,940 4 2.4% 5.2 16.8 0.0 0.1SU004 1999 Urban 4 497 6 30,555 61 66.3% 15,542 31 33.7% 1.7 47.5 0.1 2.1SU005 1999 Urban 28 514 12 424,352 826 99.8% 760 1 0.2% 14.3 51.4 0.0 0.0SU008 1999 Urban 23 3,231 11 545,917 169 92.6% 43,621 14 7.4% 8.7 37.3 0.0 0.2SU009 1999 Urban 13 2,254 12 546,622 243 92.8% 42,648 19 7.2% 2.6 20.3 0.1 0.7SU010 1999 Urban 10 1,254 10 369,200 294 78.6% 100,583 80 21.4% 4.4 42.4 0.2 2.0SU027 1999 Urban 4 458 5 120,845 264 100.0 0 0 0.0% 2.2 55.6 0.0 0.0SU097 1999 Urban 18 2,447 8 208,197 85 95.7% 9,250 4 4.3% 3.7 21.3 0.0 0.1Swan HillSHL001 1999 Long Rural 363 374 1 208,268 557 92.1% 17,871 48 7.9% 4.1 1.1 0.4 0.1SHL002 1999 Long Rural 448 1,490 5 658,072 442 93.8% 43,289 29 6.2% 2.7 0.6 0.2 0.0SHL004 1999 Short Rural 163 1,124 5 699,934 623 93.4% 49,596 44 6.6% 6.2 3.8 0.3 0.2SHL005 1999 Long Rural 297 1,314 4 600,971 457 91.9% 52,790 40 8.1% 2.8 0.9 0.2 0.1SHL007 1999 Urban 19 2,196 9 10,132 5 15.7% 54,220 25 84.3% 0.1 0.5 0.1 0.5SHL008 1999 Urban 18 2,062 8 150,832 73 52.7% 135,325 66 47.3% 1.2 6.6 0.4 2.1TerangTRG001 1999 Short Rural 114 429 3 251,257 586 87.9% 34,620 81 12.1% 3.4 3.0 0.2 0.2TRG002 1999 Long Rural 701 2,054 5 645,102 314 99.7% 1,790 1 0.3% 1.9 0.3 0.0 0.0TRG003 1999 Long Rural 332 1,560 7 1,424,497 913 93.2% 103,127 66 6.8% 7.7 2.3 0.3 0.1


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Cust.No

MVA

Total Percust

% oftotal

Total Percust

% oftotal

Total Per100km

Total Per100km

TRG004 1999 Short Rural 161 1,259 4 366,045 291 93.3% 26,142 21 6.7% 2.1 1.3 0.1 0.0TRG005 1999 Long Rural 239 1,235 4 2,215,076 1,794 90.8% 223,386 181 9.2% 13.5 5.7 1.2 0.5WarnamboolWBL001 1999 Short Rural 168 1,978 9 497,553 252 82.8% 103,604 52 17.2% 5.1 3.0 0.2 0.1WBL002 1999 Short Rural 11 2,001 2 86,534 43 100.0 0 0 0.0% 1.0 9.8 0.0 0.0WBL003 1999 Short Rural 11 453 3 64,443 142 50.0% 64,509 142 50.0% 3.7 33.7 0.9 8.5WBL004 1999 Urban 21 1,468 7 6,905 5 35.5% 12,537 9 64.5% 2.1 10.1 0.1 0.3WBL005 1999 Short Rural 121 871 3 343,705 395 98.1% 6,612 8 1.9% 3.8 3.1 0.1 0.0WBL007 1999 Long Rural 227 3,038 7 639,093 210 91.3% 60,790 20 8.7% 1.9 0.9 0.1 0.0WBL008 1999 Urban 10 1,870 3 138,647 74 100.0 0 0 0.0% 2.4 23.0 0.0 0.0WBL010 1999 Urban 7 1,161 6 109,457 94 99.2% 900 1 0.8% 1.4 21.4 0.0 0.2Waurn PondsWPD011 1999 Short Rural 101 391 2 22,999 59 82.2% 4,987 13 17.8% 1.2 1.2 0.2 0.2WPD014 1999 Short Rural 183 3,030 8 635,356 210 91.5% 58,845 19 8.5% 5.1 2.8 0.1 0.1WPD021 1999 Urban 5 3 11 0 0 0.0% 1,230 410 100.0 0.0 0.0 0.7 12.6WPD022 1999 Short Rural 126 3,514 9 624,711 178 91.3% 59,279 17 8.7% 3.0 2.4 0.1 0.1WPD024 1999 Short Rural 75 3,576 10 295,725 83 97.8% 6,770 2 2.2% 15.6 20.7 0.0 0.0WPD031 1999 Short Rural 19 1,913 4 238,097 124 94.1% 15,000 8 5.9% 3.2 17.5 0.0 0.2WPD033 1999 Urban 10 1,049 3 13,938 13 100.0 0 0 0.0% 1.3 13.1 0.0 0.0WerribeeWBE024 1999 Short Rural 53 2,136 6 189,996 89 97.7% 4,392 2 2.3% 1.1 2.0 0.0 0.0WBE031 1999 Short Rural 24 4,668 6 26,432 6 55.4% 21,285 5 44.6% 2.1 8.6 0.0 0.1WBE032 1999 Short Rural 69 5,475 10 635,226 116 98.4% 10,395 2 1.6% 9.3 13.5 0.0 0.0WBE033 1999 Short Rural 57 2,628 12 468,333 178 93.4% 33,039 13 6.6% 6.6 11.6 0.1 0.1WBE034 1999 Urban 14 2,317 11 42,959 19 100.0 0 0 0.0% 2.8 19.4 0.0 0.0WinchelseaWIN011 1999 Short Rural 71 635 1 15,206 24 23.3% 50,040 79 76.7% 4.2 5.9 0.3 0.5WIN012 1999 Long Rural 424 1,457 4 1,060,871 728 94.8% 57,956 40 5.2% 12.3 2.9 0.3 0.1WIN013 1999 Short Rural 103 510 1 191,614 376 97.8% 4,270 8 2.2% 6.9 6.7 0.1 0.1WoodendWND011 1999 Short Rural 178 1,912 8 603,330 316 94.0% 38,335 20 6.0% 5.8 3.2 0.3 0.1WND012 1999 Urban 25 986 10 1,060,352 1,075 91.4% 99,149 101 8.6% 13.9 55.7 0.3 1.2WND013 1999 Long Rural 668 3,623 9 964,823 266 31.6% 2,091,900 577 68.4% 5.2 0.8 2.4 0.4WND014 1999 Short Rural 34 1,268 7 105,072 83 100.0 30 0 0.0% 4.8 14.1 0.0 0.0WND021 1999 Short Rural 87 2,144 8 426,926 199 91.6% 39,099 18 8.4% 4.2 4.8 0.1 0.1WND022 1999 Long Rural 236 2,505 9 630,231 252 82.5% 133,552 53 17.5% 8.4 3.6 0.2 0.1WND023 1999 Long Rural 401 1,752 5 250,455 143 74.3% 86,646 49 25.7% 3.6 0.9 0.2 0.1WND024 1999 Long Rural 308 2,476 4 733,366 296 72.8% 274,504 111 27.2% 3.6 1.2 0.3 0.1


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Appendix C. FEEDER HISTORICAL PERFORMANCE CATEGORY


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Appendix D. DETERMINATION OF FEEDER FUNDAMENTAL DESIGN RELIABILITY


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GENERIC PREDICTION OF OPTIMAL FEEDER PERFORMANCE

In addition to considering past feeder performance, it is possible to model what theoptimal feeder performance should be or could have been by applying reliability analysismethodologies. To evaluate this, the following approach was adopted: -

• Construction of a technical model of the selected feeder

• Underlying capability of the network as designed and installed was determined

• Compare current capability with model

• Reconstruction of the feeder with equipment proposed to be installed under therefurbishment capex plan

• Comparison of the reconstructed feeder with current capability

• Comparison of the feeder performance using modern equivalent assets againstcurrent capability

Reliability Model

The reliability model activities can be divided into two fundamental segments ofmeasuring past performance and predicting future performance. The accuracy ofhistorical data is very important for the accuracy of the results of the reliability modelling.The level and complexity of the data collection system is dependent upon the use to bemade of these data. Some of the applications are:

• To produce performance data regarding quality of customer service on thedistribution system

• To identify feeders with substandard performance and to ascertain causes

• To provide data for comparison of performance between companies

• Obtain the optimum improvement in reliability per dollar expended for design,maintenance and operating programmes

• Provide performance data for a probabilistic approach to reliability studies

• Provide a basis for individual companies to establish service continuity criteria.This could be used to monitor system performance and to evaluate generalpolicies, practices, standards and design

• Provide data for analysis to determine reliability of service in a given area(geographical, political, operating etc.) to determine how factors such as designdifferences, environment or maintenance methods and operating practices thataffect performance

• Provide reliability history of individual feeders for analysis

Objective of Reliability Modelling as a Part of This Investigation

The main objective of the reliability modelling part of this project is to objectively compareand evaluate the effects on the selected HV feeder performance of varying theconfiguration, protective methods, equipment, structural design, operating andmaintenance practices. Also using a probabilistic approach, this modelling could beused to determine the design, operating and maintenance practices that would provideoptimum reliability per dollar expended by predicting the future performance.

The Capability of the Model

• The model was used to analyse the past performance of the feeder

• It can forecast and analyse the future performance of the feeder for differentimprovement options such as addition of new equipment, change of operation andmaintenance practices, new replacement strategies, reconfigurations etc


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The model was used to objectively determine the economic feasibility of reliabilityimprovement projects and thereby rank the reliability improvement projects usingdiscounted cash flow methods

Data Required to Model the Feeder

• Complete outage history, customer numbers and failure rates of sections andcomponents of relevant feeders to determine the parameters to be used in themodelling

• Repair times for various types of faults

• Powercor future capital investment plan in relation to load growth, reliabilityimprovements and their maintenance and replacement strategies to evaluate theeconomic feasibility

• The load data, conductor data and other equipment data available for the feederand adjacent feeders

• Condition assessment of the equipment associated with the feeder

• Outage history of zone substations which the relevant feeders are supplied from

• Information about Lightning activity in the area

• Bush fire risk in the relevant areas and Powercor bushfire mitigation programme

• Powercor planning guidelines/criteria and switching guidelines

Component Model for Reliability Evaluation

A system configuration consists of many components and all reliability assessmentmethods need the data in terms of component failure rate and repair duration. Manydistribution systems can be analysed by series-parallel reduction techniques for whichthere are relatively simple formulae available. A single component can be modelledusing the very basic two states Markov model as shown in the figure below. Thesestates are the operating (available) state and the failed (unavailable) state.

The HV feeder was modelled as a multiple component (depending on the number ofcomponents to be considered) reliability model connected in series. The system wasanalysed using series reduction techniques subject to constraints. Many distributionfeeders could be analysed this way because of the existence of normally open points inthe overall configuration.

The outage duration and the number of customers affected were reduced usingprotection and sectionalising schemes. This means that by isolating the faulted section,supply can be restored to some of the load points while the faulted section is beingrepaired. The time taken by this type of isolation and switching action is referred to asthe restoration time. The repair time in some load points will be the restoration timedepending on whether supply can be re-established or not by switching actions. Aspreadsheet-based work sheet developed by PB Power was used to perform therequired calculations for the HV feeders.


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Reliability Modelling Process for Selected HV Feeder

The following method was used to model the selected HV feeder to achieve the aboveobjectives: -

• Develop the reliability model for the feeder using different component reliabilitymodels of the feeder such as feeder sections, feeder circuit breakers, reclosers,sectionalisers, fuses connected in series

• From the data provided determine the average load of each section

• Calculate reliability indices, availability, unavailability and Expected Energy NotSupplied (EENS) for different scenarios and quantify the worth of reliability

• Change various parameters to study the impact of new investments, changedoperating and maintenance practices and calculate the reliability indices and worthof reliability

• Use the above calculations to prepare economic evaluations of various capitalinvestment options and changed operating and maintenance practices


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Appendix E. DOCUMENT LIST


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List of Documents used for Powercor Feeder Reliability and Expenditure Review

DocNo Document Name

P1 Letter from Powercor to John Tamblyn re inquiry 22.3.00

P4 Group of newspaper clippings March 00

P5 Letter to Powercor on pole fire incidents from Office of Chief Electrical Inspector21.3.00

P6 Letter to Powercor from Office on inquiry 24.3.00

P7 Letter to Powercor from Office on inquiry setting up first meeting 23.3.00

P8 Process chart, data requirements and Gantt chart table at meeting on 4.4.00

P9 List of poor performing feeders supplied by Office 30.3.00

P10 E-mail from Kieran Skelton on outage data definitions 3.4.00

P11 Network diagram

P12 Shire map

P13 Network functional diagram

P14 Powercor zone substation coverage map

P15 Minutes of meeting with Powercor 3.4.00


P18 Feeders selected for detailed review tabled with Powercor 6.4.00

P19 E-mail from Keiran Skelton defining outage categories

P20 Powercor 5.4.00 media release re $2m maintenance program underway inGeelong region

P21 Powercor Bushfire Mitigation Management Framework – not dated

P22 Powercor asset management strategy presentation to Utilities Insurance meeting17.7.98

P23 Work carried out on selected feeders over last 3 years

P24 Forecast work for selected feeders

P25 Powercor overhead line asset in service failures fire/non fire 1.1.98 to 31.1.00

P26 Timing of work on selected feeders

P27 White board printout to short list 22 down to 7 pre meeting with ORG

P28 Letter from Minister for Energy and Resources dated 4.4.00 together withTreasury and Finance paper

P30 Information requirements status 12.4.00

P31 Confidentiality deed tabled by Powercor on 11.4.00 (Phillips Fox)

P32 Letter dated 12.4.00 from Ian Wilson to Anne Eakin

P33 Powercor proposed information and meeting schedule

P34 Newspaper clipping supplied by ORG 13.4.00

P35 Information Requirements for stages two and three – Powercor status


P37 Powercor overall network map and schematics of feeders to be reviewed

P38 Powercor AMP table of content supplied 13.4.00

P39 Powercor action plan for collecting information for review and site visits supplied


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DocNo Document Name

13.4.00

P40 Powercor Asset Management Strategy

P41 Powercor Quality Database Help Document (price review)

P42 Network Capability Statement for selected feeders

P43 Identify and Repair Defect Procedure

P44 Vegetation Management Plan

P45 Asset Inspection Work Practices Manual part 1 draft 1 issued 17/3/99 (see P49 forpart 2)

P46 VESI Standards (on CD)

P47 Information Requirements for stages two and three – updated 14.4.00 – as givento I Wilson

P48 Information Requirements for stages two and three – updated 15.4.00

P49 Asset Inspection Work Practices Manual part 2 draft 1 issued 17/3/99 (see P45 forpart 1)

P50 Capex by feeder spread sheet – e-mail from Kieran Skelton 18.4.00 REPLACEDBY P117

P51 Bush fire mitigation report for week ending 17.4.00 – e-mail from Kieran Skelton18.4.00

P52 Answer to PB questions updated by KS 18.4.00

P53 Business cases for SWER program – year 2000 network performance

P54 Business case for fault indicator installation 2000

P55 Business case for auto reclose monitoring (stage II) using DCI sentry system

P56 BAN8 protection settings

P57 Extract from Service Standards section of Pricing Submission to ORG

P58 Printout from Powercor reliability model SEE P126

P59 Reliability model structure SEE P126

P60 Feeder capital expenditure 1997/98/99 REPLACED BY P117

P61 Feeder operational expenditure 1997/98/99

P62 Automation projects - extract from works program listing work planned on a rangeof feeders (not sure for what year)

P63 Analysis of load growth forecasts on Edenhope Line

P64 Code of Practice for Powerline Clearance (vegetation) 1996 Office of the ChiefElectrical Inspector

P65 Unplanned shutdown/faults procedure – issued 4 13.5.96

P66 Works Management Structure 1999

P67 Switching: Feeder Patrols and Supply Restoration on HV Overhead Lines issue 125.5.98

P68 PB Power visits and timetable updated 19.4.00

P69 Demand side management on HSM2

P70 Network Planning Policy and Guidelines version 1 20.5.99

P71 Maintenance timetable

P72 Maintenance process flow diagrams


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DocNo Document Name

P73 Notes on process flow diagrams

P74 Further notes on process flow diagrams

P75 BAN008 completed maintenance

P76 BAN015 completed maintenance

P77 GL022 completed maintenance

P78 HSM002 completed maintenance

P79 STN003 completed maintenance

P80 SU004 completed maintenance

P81 SU005 completed maintenance

P82 TRG001 completed maintenance

P83 TRG005 completed maintenance

P84 WPD014 completed maintenance

P85 WND012 completed maintenance

P86 Number not used

P87 Forecast maintenance on selected feeders supplied by Maintenance Manager21.4.00 (same as P24)

P88 Powercor Construction Standards

P89 Powerpoint presentation on automation, DCI sentry devices and DaylesfordProject

P90 Minutes of meeting with Powercor on 19 April

P91 Notes of meetings with Powercor on 20 April

P92 Emails from Mike Swanston approving projects

P93 Morlynn insulator letter dated 9.2.00 re pin insulator H11434

P94 Cooper Power Systems paper 1235-35 on Surge Arrestors

P95 Supplementary submission to the Regulator General 2001 Electricity DistributionPrice Review 20 April 2000+

P96 Presentations from visit to Network Operations and Call Centre

P97 Network Asset Performance Organisational Chart

P98 Information requirements for stages two and three updated 1 May

P99 Notes of meeting with Vikram Singh

P100 Notes of visit to Bendigo

P101 Service Agent Boundaries

P102 Status of SCADA in Powercor

P103 BAN008 data (diagram)

P104 Notice of completion of fire mitigation obligations

P105 Notes of Meetings with M Swanston and J Mifsud 3 May 2000

P106 BAN08 line fuses

P107 BAN08 load flow output

P108 BAN08 voltage profile per phase along sections

P109 BAN08 customer numbers per switching zone


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DocNo Document Name

P110 BAN08 estimated maximum demands 2000 to 2010

P111 Notes of meeting with Bryan Quinn

P112 “Surge in power pole fires” Geelong Advertiser Wednesday 3 May

P113 Powercor high level organisational structure 23 November 1999

P114 Powercor Performance :Results from International Benchmarking

P115 Asset inspection performance vs program 1999

P116 Status of outstanding 1998 Capex and OPEX maintenance work

P117 Capex by feeder (updated)

P118 Screen dump of Draft BMF Procedures

P119 Horsham ZSS Area Planning Report

P120 Ballarat ZSS Area Planning Report

P121 Terang ZSS Area Planning Report

P122 Description of “THE MODEL OUTPUT version 2” Word Document

P123 Excel Spreadsheet “Sheet 13 Model”

P124 Excel Spreadsheet “Dupont”

P125 Excel Spreadsheet “Capspend160166d”

P126 Excel Spreadsheet “Model 2001 reliability capex 2001 2002”

P127 March 2000 Network Business Report (less commercially sensitive material)

P128 April 2000 Network Performance Report (less commercially sensitive material)


P130 Response regarding TRG001 and TRG005

P131 Horsham Load Growth

P132 Breakdown of Supplementary Submission costs and reliability changes

P133 Notes of Meeting with Powercor 28th April – Network Reliability

P134 Notes of Meeting with Powercor 24th March – Kick Off meeting

P135 BAN008 connectivity

P136 Area planning information (planning studies not available) for WND, WPD and GL

P137 Project information for SU and GE areas

P138 Excel spread sheet aperf9899projects


P140 Excel spreadsheet Psolutionscosts

P141 Excel spreadsheet Sensitive feeders 2003-2005

P142 Confirmation of customer numbers used for reporting

P143 Notes of meeting with Powercor 12_5_00

P145 Overview report on 22 kV feeders DDL23 and WPD22

P146 Reliability Expenditure Overall

P148 Newspapers clippings

P149 Planning report SU05 10 April 2000

P150 Feeder profile SU05 12 February 2000


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DocNo Document Name

P151 Business case and area planning report for new WND021 (no date) – inclWND012 details

P152 Melton, Sunbury, Woodend network subtransmission planning report

P153 Load flow report KTS-SBY-MLN-WND loop

P154 WPD014 feeder profile March 1999

P155 Approved planning report new LVN zone sub, LVN01 feeder 7 Sept 1999

P156 Project summary and financial arrangements for new LVN zone substation 7 April2000

P157 Cover letter from Powercor for documents P149-156