2016-17 to 2020-21 document ue pl 2209 - united energy · 2017-10-05 · distribution annual...

Distribution Annual Planning Report (DAPR)

2016-17 to 2020-21

Document № UE PL 2209

Strategy This document details how UE plans to

manage and develop the electricity distribution network over the next five years as part of the National Distribution Planning & Expansion Framework.

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Strategy – Distribution Annual Planning Report (DAPR) Document № UE PL 2209

Review by: 12/2017 Page 1 of 370

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Strategy – Distribution Annual Planning Report (DAPR) Document № UE PL 2209 Review by: 12/2017 Page 2 of 370

Table of Contents

1 Approval and Document Control 8

2 Executive summary 9

3 Introduction 19

3.1 Purpose of the DAPR 19

3.2 UE’s obligations under the Distribution Planning & Expansion Framework 19

3.2.1 Annual planning review and reporting 20

3.2.2 Demand side engagement 21

3.2.3 Regulatory Investment Tests for Distribution 22

3.2.4 Request for submissions 22

3.2.5 Joint planning 23

3.2.5.1 Victorian arrangements for transmission connection assets 23

3.2.5.2 Victorian arrangements for shared distribution assets 23

3.3 Significant changes from 2015 DAPR 24

3.3.1.1 Maximum demand forecast 24

3.3.1.2 Value of Customer Reliability (VCR) 25

3.3.1.3 Discount Rate 25

3.3.1.4 Timing of proposed network augmentations 25

3.4 Feedback on UE’s 2015 DAPR 26

3.5 DAPR structure 26

4 Network overview 29

4.1 Overview of United Energy 29

4.2 Summer 2015-16 maximum demand 30

4.3 Assets covered 32

4.3.1 Description of network assets 33

4.3.1.1 Terminal stations 33

4.3.1.2 Sub-transmission systems 34

4.3.1.3 Zone substations 35

4.3.1.4 High voltage distribution feeders 36

4.3.1.5 Distribution substations 39

4.3.1.6 Low voltage network 39

4.3.1.7 Service lines 39

4.3.1.8 Communications network 39

4.3.1.9 Meters 39

4.3.1.10 Asset management information systems 40

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4.4 Operating environment 41

4.4.1 Factors influencing maximum demand 41

4.4.1.1 Economic growth 41

4.4.1.2 Population growth 42

4.4.1.3 Price 42

4.4.1.4 Temperature sensitive loads 42

4.4.1.5 Energy efficiency 43

4.4.1.6 Distributed generation 44

4.4.1.7 Demand management 44

4.4.1.8 Distributed storage 45

4.4.1.9 Electric Vehicles 45

4.4.2 Network utilisation and load factor 46

4.4.3 Weather-corrected maximum demand 47

4.4.4 Asset age and condition 48

4.4.5 Fault level 50

4.4.6 Quality of Supply (QoS) 52

4.4.7 Extreme Weather 53

4.4.8 Regulatory environment 53

5 Maximum demand forecast 54

5.1 Maximum demand forecast method 54

5.2 Forecasting assumptions 55

5.2.1 Actual maximum demand calculations 55

5.2.2 Weather-correction 56

5.2.2.1 Excluded days 56

5.2.2.2 Reference temperatures 57

5.2.3 New and retiring developments 58

5.3 Maximum demand forecast accuracy 58

6 Network development plan 60

6.1 Network development planning process 60

6.2 Planning standards 62

6.2.1 Reliability and security of supply standards 62

6.2.2 Energy loss reduction standards 63

6.3 Key assumptions that drive timing of augmentation 64

6.3.1 Forecast summer maximum demand growth 64

6.3.2 Value of Customer Reliability 64

6.3.3 Plant forced outage rates and durations 65

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6.3.4 Plant thermal ratings 66

6.3.5 Discount rates 66

6.3.6 Load transfer capability 66

6.4 Committed augmentation projects 66

6.5 Forecast distribution network limitations overview 68

6.6 Summary of Regulatory Investment Test for Distribution undertaken 79

6.6.1 Current Regulatory Investment Test for Distribution 79

6.6.1.1 Lower Mornington Peninsula Supply Area RIT-D 80

6.6.1.2 Notting Hill Supply Area RIT-D 81

6.7 Summary of joint planning outcomes 82

6.8 Summary of projects to address urgent and unforeseen network issues 82

6.9 Forecast distribution network limitations 82

6.9.1 Zone substations 83

6.9.1.1 Box Hill zone substation 83

6.9.1.2 Beaumaris zone substation 86

6.9.1.3 Bentleigh zone substation 88

6.9.1.4 Bulleen zone substation 92

6.9.1.5 Burwood zone substation 96

6.9.1.6 Clarinda zone substation 98

6.9.1.7 Caulfield zone substation 102

6.9.1.8 Cheltenham zone substation 105

6.9.1.9 Carrum zone substation 107

6.9.1.10 Doncaster zone substation 112

6.9.1.11 Dromana zone substation 117

6.9.1.12 Dandenong zone substation 119

6.9.1.13 Dandenong South zone substation 123

6.9.1.14 Dandenong Valley zone substation 127

6.9.1.15 East Burwood zone substation 129

6.9.1.16 Elsternwick zone substation 131

6.9.1.17 East Malvern zone substation 135

6.9.1.18 Elwood zone substation 139

6.9.1.19 Frankston South zone substation 141

6.9.1.20 Frankston zone substation 146

6.9.1.21 Glen Waverley zone substation 150

6.9.1.22 Hastings zone substation 154

6.9.1.23 Heatherton zone substation 158

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6.9.1.24 Gardiner zone substation 160

6.9.1.25 Keysborough zone substation 164

6.9.1.26 Lyndale zone substation 168

6.9.1.27 Langwarrin zone substation 170

6.9.1.28 Mentone zone substation 172

6.9.1.29 Mordialloc zone substation 174

6.9.1.30 Mulgrave zone substation 178

6.9.1.31 Moorabbin zone substation 182

6.9.1.32 Mornington zone substation 185

6.9.1.33 North Brighton zone substation 189

6.9.1.34 Notting Hill zone substation 193

6.9.1.35 Noble Park zone substation 197

6.9.1.36 Nunawading zone substation 199

6.9.1.37 Oakleigh zone substation 201

6.9.1.38 Oakleigh East zone substation 203

6.9.1.39 Ormond zone substation 205

6.9.1.40 Rosebud zone substation 209

6.9.1.41 Surrey Hills zone substation 213

6.9.1.42 Sandringham zone substation 215

6.9.1.43 Springvale South zone substation 217

6.9.1.44 Sorrento zone substation 221

6.9.1.45 Springvale and Springvale West zone substations 225

6.9.1.46 West Doncaster zone substation 229

6.9.2 Sub-transmission systems 231

6.9.2.1 CBTS sub-transmission system 231

6.9.2.2 ERTS sub-transmission systems 237

6.9.2.3 HTS sub-transmission systems 245

6.9.2.4 MTS sub-transmission systems 254

6.9.2.5 RTS sub-transmission systems 263

6.9.2.6 RWTS sub-transmission system 272

6.9.2.7 SVTS sub-transmission systems 275

6.9.2.8 TBTS sub-transmission systems 288

6.9.2.9 TSTS sub-transmission systems 299

6.9.3 Distribution high-voltage feeders 306

7 Demand management activities 310

7.1 Network Support Agreements in the past year 310

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7.2 Demand Management Incentive Scheme initiatives in the past year 310

7.2.1 District Energy Services Scheme 311

7.2.2 Virtual Power Plant Pilot 312

7.2.3 Bulleen “Summer Saver” Demand Response Pilot 313

7.3 Actions taken to promote non-network solutions in the past year 314

7.4 Plans for future non-network solutions 315

7.5 Connection of Embedded Generation (EG) units 316

7.5.1 Key issues from applications to connect EG units in the past year 317

7.5.2 Quantitative summary of connection application to connect EG units 317

8 Network performance 319

8.1 Network reliability 319

8.1.1 Reliability performance measures and targets 319

8.1.2 Reliability performance 320

8.1.3 Reliability performance review process 322

8.1.4 Reliability corrective actions and initiatives 323

8.1.5 Information submitted to the AER 324

8.1.6 Reliability performance forecast 324

8.2 Power quality 325

8.2.1 Power quality strategy 325

8.2.1.1 Power quality monitoring capability 326

8.2.1.2 Power quality analysis 328

8.2.1.3 Power quality management process 329

8.2.2 Power quality standards 329

8.2.3 Power quality performance 330

8.2.3.1 Steady state voltage 330

8.2.3.2 Voltage unbalance 332

8.2.3.3 Voltage harmonic distortion 334

8.2.3.4 Flicker 336

8.2.3.5 Voltage sags 339

8.2.4 Power quality corrective actions and initiatives 340

9 Asset management 343

9.1 Asset management system 343

9.1.1 Asset Management Strategy and Objectives 345

9.1.2 Asset Class Strategies and Plans 347

9.1.3 Asset Management Plan and COWP 347

9.1.4 Works Program 348

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9.1.5 Works planning and execution 348

9.2 Asset replacement programme 349

9.2.1 Summary of planned replacement projects 349

9.2.2 Impact on network limitations 350

10 Metering and Information Technology 351

10.1 Advance Metering Infrastructure 351

10.1.1 Overview 351

10.1.1.1 AMI programme 352

10.1.2 AMI solution 352

10.1.3 Meter contestability 353

10.1.4 Investment in metering 354

10.2 Information Technology Systems 355

10.2.1 Investment in IT Systems in 2015-16 355

10.2.2 Investment in IT Systems over the forward planning period 2017-2021 356

11 Abbreviations and Glossary 358

Appendix A – Transmission Connection Planning 362

Appendix B – NER Schedule Cross-References 365

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1 Approval and Document Control

VERSION DATE AUTHOR

1 December 2016 UE Network Planning

Amendment overview

New document

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2 Executive summary

United Energy (UE) is a regulated Victorian electricity distribution business with an electricity distribution network covering 1,472 square kilometres and serving approximately 664,500 customers throughout Melbourne’s south east and the Mornington Peninsula. This Distribution Annual Planning Report (DAPR) details how UE plans to manage and develop the electricity distribution network with the objective of delivering adequate, economic, reliable and safe supply of electricity to customers over the five year planning period from 2016-17 to 2020-21. This report is prepared in accordance with clause 5.13 and schedule 5.8 of the National Electricity Rules (NER). Furthermore, this report discharges UE's obligations under clause 3.5 of the Victorian Electricity Distribution Code regarding the publication of an annual distribution system planning report.

This DAPR provides information on UE’s:

Obligations under the distribution planning and expansion framework;

Distribution network, the operating environment and the number and type of distribution assets;

Significant changes to this DAPR compared to the 2015 DAPR;

Asset management approach and annual planning process, methods and assumptions;

Forecasts, including capacity and maximum demand at the transmission-connection, sub-transmission, zone substation and high-voltage distribution feeder level;

Present and emerging network limitations including identified preferred network solutions to address those limitations;

Likely network augmentations within the planning period are flagged to give interested parties the opportunity to offer alternative proposals to alleviate the limitations. These proposals may include non-network options such as demand management or embedded generation solutions;

Regulatory Investment Test for Distribution (RIT-D) assessments that have been completed or currently underway;

Upcoming RIT-D assessments;

Demand management activities;

Recent network performance and improvement initiatives;

Asset replacement / refurbishment plans; and

Metering and Information Technology Systems investment plans.

One of the purposes of this DAPR is to facilitate the efficient development of the distribution network to best meet the needs of customers. This report identifies major limitations in:

2 sub-transmission systems;

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2 zone substations; and

6 high-voltage distribution feeders.

In the absence of any commitment by interested parties to offer network support, the capital programme summarised in the tables below is likely to be undertaken when the network augmentations become economic. Parties seeking further information on UE’s asset management strategy and / or parties interested in proposing alternative solutions wanting to seek additional information should direct their enquiries to [email protected].

mailto:[email protected]

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Summary of distribution network limitations

LIMITATION 1 – EAST BURWOOD SUPPLY AREA

Limitation Sub-transmission

If there is a forced outage of critical sections of the SVTS-EB-RD-SVTS sub-transmission during summer maximum demand periods, there will be insufficient capacity on this system to supply all demand from summer 2016-17.

This system is presently limited by the SVTS-EB 66 kV line, for an outage of the SVTS-RD 66 kV line.

Location The suburbs most likely to be affected include Burwood East and Forest Hill presently supplied by UE’s East Burwood (EB) zone substation

Preferred network solution

Description Re-conductor 0.75km of the SVTS-EB 66 kV line

Cost estimate $530,000

Timing Before summer 2017-18

Non-network solution requirements

Main customer groups

The main contribution to the summer maximum demand comes from the commercial and the residential sector air-conditioning demand on hot summer days. Opportunities for demand reduction therefore exist in the commercial and residential voluntary load reduction schemes

Type of solution In order to avoid supply interruptions to customers connected to EB zone substation, post-contingent non-network solutions are required

Timing Non-network solutions must be implemented by summer 2017-18

Operating characteristics

To defer the proposed augmentation by 12 months, a non-network solution would need to reduce the maximum demand at EB zone substation, between the hours of 15:00 to 20:00 on weekdays by approximately 4.0 MVA

Network support payment

The estimated total annual cost of the preferred option is around $33,800. This provides a broad upper bound indication of the maximum contribution from UE which may be available to non-network service providers for deferring or avoiding the need for proposed network augmentation

Status UE welcomes interested parties to submit their proposals or engage in joint planning now to defer or avoid the proposed network augmentation

Reference For further information about limitation refer to Section 6.9.2.7

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LIMITATION 2 – DONCASTER / TEMPLESTOWE SUPPLY AREA


If there is a forced outage of critical sections of the TSTS-DC-TSTS sub-transmission system during summer demand periods, there will be insufficient capacity on this system to supply all demand from summer 2016-17.

Location The suburbs and areas most likely to be affected include Box Hill Central, Box Hill North, Doncaster, Doncaster East, Doncaster Hill and Templestowe


Description Up-rate TSTS-DC No.1 66kV line and droppers which is strung on towers owned by AusNet Transmission Group by 2017-18.

Cost estimate $0.2 million





Type of solution In order to avoid supply interruptions to customers connected at DC zone substation, post-contingent non-network solutions are required

Timing Non-network solutions must be implemented by summer 2017-18.


To defer the proposed augmentation by 12 months, a non-network solution would need to reduce the maximum demand at DC zone substation, between the hours of 14:00 to 20:00 on weekdays by approximately 1.0 to 2.0 MVA.


The estimated total annual cost of the preferred option is $12,740. This provides a broad upper bound indication of the maximum annual contribution from UE which may be available to non-network service providers for deferring or avoiding the need for proposed network augmentation.

Status Exempted from RIT-D assessment

However, UE welcomes interested parties to submit their proposals or engage in joint planning to defer or avoid the proposed network augmentation works


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Limitation Zone substation

If there is a forced transformer outage at Doncaster (DC) zone substation during summer maximum demand periods, there will be insufficient capacity at DC zone substation to supply all demand from summer 2016-17. As a consequence, some customers supplied from DC zone substation are exposed to risk of supply interruption.

Distribution feeders

A number of distribution feeders within the DC supply area are highly utilised. This can limit transfer capability between feeders during emergency conditions. As a consequence, some customers are exposed to risk of supply interruption.

A number of distribution feeders have shown poor reliability performance compared to the overall UE network. More specifically, DC 1, DC 3, DC 4, DC 5, DC 6 and DC 12 are amongst UE’s top 50 worst performing feeders.



Description Install a fourth 20/33 MVA 66/22 kV transformer at DC zone substation together with two new high-voltage distribution feeders.

An alternative option being considered is the establishment of a new single transformer zone substation in Templestowe.

Cost estimate $8 million








To defer the proposed augmentation by 12 months, a non-network solution would need to reduce the maximum demand at DC zone substation, between the hours of 15:00 to 20:00 on weekdays by approximately 3.0 MVA



Status Identified for RIT-D assessment within the next 12 months

UE welcomes interested parties to submit their proposals or engage in joint planning to defer or avoid the proposed network augmentation


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LIMITATION 4 – EAST MALVERN SUPPLY AREA


If there is a forced transformer outage at East Malvern (EM) zone substation during summer maximum demand periods, there will be insufficient capacity at EM zone substation to supply all demand from summer 2016-17. As a consequence, some customers supplied from EM zone substation are exposed to risk of supply interruption


A number of distribution feeders within the EM supply area are highly utilised. This can limit transfer capability between feeders during emergency conditions. As a consequence, some customers are exposed to risk of supply interruption

Location The suburbs most likely to be affected include Alamein, Carnegie, Chadstone and East Malvern


Description Install a third 20/33 MVA 66/22 kV transformer at EM zone substation





The main contribution to the summer maximum demand comes from the commercial, residential and light-industrial sectors. Opportunities for demand reduction therefore exist in the commercial, residential and light-industrial voluntary load reduction schemes.

Type of solution In order to avoid supply interruptions to customers connected at EM zone substation, post-contingent non-network solutions are required.



To defer the proposed augmentation by 12 months, a non-network solution would need to reduce the maximum demand at EM zone substation, between the hours of 15:00 to 20:00 on weekdays by approximately 3.0 MVA.


The estimated total annual cost of the preferred option is around $446,000. This provides a broad upper bound indication of the maximum annual contribution from UE which may be available to non-network service providers for deferring or avoiding the need for proposed network augmentation.

Status Identified for RIT-D assessment beyond next 12 months.

UE welcomes interested parties to engage in joint planning to defer or avoid the proposed network augmentation


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LIMITATION 5 – WELLS RD, CHELSEA / CHELSEA HEIGHTS / ASPENDALE GARDENS / BANGHOLME AREA

Limitation Distribution feeder

CRM 35 feeder is a highly utilised feeder.

Location The suburbs most likely to be affected include some parts of Chelsea, Aspendale Gardens, Chelsea Heights, Edithvale and Bangholme electricity supply areas


Description Extend CRM 24 feeder to offload CRM 35

Cost $400,000







To defer the proposed augmentation by 12 months, a non-network solution would need to reduce the maximum demand on CRM 35, between the hours of 14:00 to 20:00 by approximately 0.5 MVA before summer 2018-19


The estimated total annual cost of the preferred option is $25,500. This provides a broad upper bound indication of the maximum contribution from UE which may be available to non-network service providers for deferring or avoiding the need for proposed network augmentation

Status UE welcomes interested parties to submit their proposals now to defer or avoid the proposed network augmentation

Reference For further information about limitation refer to Section 6.9.3

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LIMITATION 6 – DANDENONG FRANKSTON RD, CARRUM DOWNS / DANDENONG SOUTH / SANDHURST AREA


DVY 24 feeder is a highly utilised feeder. The maximum demand on DVY 24 feeder is expected to exceed its summer cyclic rating from 2018-19.

Location The suburbs most likely to be affected include portion of Dandenong South, Carrum Downs and Sandhurst electricity supply areas


Description Build a new feeder DVY 12 to offload DVY 24

Cost $900,000







To defer the proposed augmentation by 12 months, a non-network solution would need to reduce the maximum demand on DVY 24, between the hours of 13:00 to 19:00 by approximately 2.0 MVA before summer 2018-19





LIMITATION 7 – GLENHUNTLY RD, ELSTERNWICK AREA


The maximum demand on EL 10 feeder is expected to exceed its summer cyclic rating from 2018-19.

Location This feeder supplies electricity along Glen Huntly Rd in the Elsternwick area


Description Build new EW feeder to offload EL 10

Cost $1.2 million




The main contribution to the summer maximum demand comes from the commercial sector on hot summer days. Opportunities for demand reduction therefore exist in the commercial voluntary load reduction schemes



To defer the proposed augmentation by 12 months, a non-network solution would need to reduce the maximum demand on EL 10 between the hours of 14:00 to 19:00 by approximately 4.0 MVA before summer 2018-19





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LIMITATION 8 – MT ELIZA WAY, MOUNT ELIZA / FRANKSTON FLINDERS RD, FRANKSTON SOUTH AREA


FSH 33 feeder is a highly utilised feeder during hot summer periods

Location The suburbs most likely to be affected include Mt Eliza and Frankston South

Preferred

network

solution

Description Build new feeder at FSH to offload FSH 33

Cost $330,000







To defer the proposed augmentation by 12 months, a non-network solution would need to reduce the maximum demand on FSH 33, between the hours of 16:00 to 20:00 by approximately 0.5 MVA before summer 2018-19



Status UE welcomes interested parties to submit their proposals to defer or avoid the network augmentation


LIMITATION 9 – HALL RD, CARRUM DOWNS / SEAFORD / SKYE AREA


FTN 23 feeder is a highly utilised feeder

Location The suburbs most likely to be affected include Carrum Downs, Seaford and Skye

Preferred

network

solution

Description Permanent load transfer from FTN 23 feeder onto adjacent lightly loaded FTN 25 feeder

Cost $26,000







To defer the proposed augmentation by 12 months, a non-network solution would need to reduce the maximum demand on FTN 23, between the hours of 16:00 to 21:00 by approximately 0.5 MVA before summer 2017-18





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LIMITATION 10 – JELLS RD / FERNTREE GULLY RD, WHEELERS HILL AREA


The maximum demand on MGE 12 feeder is expected to exceed its summer cyclic rating from 2017-18.

Location The suburbs most likely to be affected include Scoresby and Wheelers Hill.


Description Establish new 22 kV feeder from MGE zone substation

Cost $1.4 million




The main contribution to the summer maximum demand comes from the commercial sector. Opportunities for demand reduction therefore exist in the commercial voluntary load reduction schemes.



To defer the proposed augmentation by 12 months, a non-network solution would need to reduce the maximum demand on MGE 12, between the hours of 11:00 to 18:00 by approximately 3.7 MVA before summer 2018-19.


The estimated total annual cost of the preferred option is $89,200. This provides a broad upper bound indication of the maximum contribution from UE which may be available to non-network service providers for deferring or avoiding the need for proposed network augmentation.

Status UE welcomes interested parties to submit their proposals to defer or avoid the network augmentation.


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3 Introduction

This Distribution Annual Planning Report (DAPR) provides a comprehensive overview of how UE will manage and develop the electricity distribution network with the objective of delivering adequate, economic, reliable and safe supply of electricity to customers over the next five years from 2016-17 to 2020-21.

3.1 Purpose of the DAPR

The DAPR is prepared in accordance with clause 5.13 and schedule 5.8 of the National Electricity Rules (NER). This report also discharges UE's obligations under clause 3.5 of the Victorian Electricity Distribution Code regarding the publication of an annual distribution system planning report. This report is structured to provide information on:

UE’s obligations under the distribution planning and expansion framework;

UE’s distribution network, the operating environment and the number and type of distribution assets;

Any significant changes from the 2015 DAPR;

Asset management approach and annual planning process, methods and assumptions;

Forecasts, including capacity and maximum demand at the transmission-connection, sub-transmission, zone substation and high-voltage distribution feeder level;

Present and emerging network limitations including identified preferred network solutions to address those limitations;

Likely network augmentations within the planning period are flagged to give interested parties the opportunity to offer alternative proposals to alleviate the limitations. These proposals may include non-network options such as demand management or embedded generation solutions;

Summary of Regulatory Investment Test for Distribution (RIT-D) assessments that have been completed or currently underway;

Upcoming RIT-D assessments;

Demand management activities;

Recent network performance and improvement initiatives;

Asset replacement / refurbishment plans; and

Investment plans for Metering and Information Technology Systems.

3.2 UE’s obligations under the Distribution Planning & Expansion Framework

In January 2013, the Australian Energy Market Commission (AEMC) established a consistent national framework for distribution network planning and expansion. The national framework is

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applicable to UE’s planning activities. This new framework requires UE to prepare and publish an annual planning report, consult with interested parties on possible alternative solutions to address emerging network limitations, undertake joint planning and undertake analysis of proposed network investment using the RIT-D.

3.2.1 Annual planning review and reporting

Under the national framework, UE must conduct an annual planning review and publish an annual report as an outcome of the review. This report is called the Distribution Annual Planning Report (DAPR) and is prepared in accordance with clause 5.13 of the NER. More specifically:

The annual planning review must be over a minimum five year forward planning period;

The results of the annual planning review for the forward planning period must be published annually in the DAPR by 31 December;

The DAPR must include information specified in schedule 5.8 of the NER; and

The DAPR can exclude information in relation to transmission connection assets, if it is required under jurisdictional electricity legislation.1

In order to fulfil UE’s jurisdictional obligations under clause 3.5 of the Victorian Electricity Distribution Code, this DAPR can be interpreted to be the Distribution System Planning Report (DSPR).

Pursuant to clause 5.13.2(d) of the NER, information in relation to transmission connection asset planning required under schedule 5.8 is addressed in the 2016 Transmission Connection Planning Report (TCPR), as explained in Appendix A to this DAPR. The table below lists the relevant clauses of schedule 5.8 that are addressed in the 2016 TCPR.

Table 1 – Schedule 5.8 requirements addressed in Transmission Connection Planning Report

Schedule 5.8 clause Matters addressed

S5.8(a)(4) A description of the methodology used to identify system limitations.

S5.8(a)(5) An explanation of any significant changes in demand forecasts from previous forecasts and the impact on the network development plan.

S5.8(b)(1) A description of the forecasting methodology used.

S5.8(b)(2)(i) Load forecasts and forecasts of capacity.

S5.8(b)(3) Forecasts of future transmission-distribution connection points and any associated connection assets.

S5.8(h) The results of joint planning undertaken with Transmission Network Service Providers.

1 In Victoria, UE is required, under the Victorian Electricity Distribution Code clause 3.4, to undertake an annual planning review of the transmission connection assets and publish a joint report called the Transmission Connection Planning Report (TCPR). This report is attached as an Appendix A to this DAPR.

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Schedule 5.8 clause Matters addressed

S5.8(n)(2) A map identifying present and emerging transmission connection asset limitations.

3.2.2 Demand side engagement

One of the purposes of the DAPR is to provide information to interested parties on present and emerging network limitations. Our aim is to alleviate network limitations in a manner that maximises the present value of net market benefits. UE therefore encourages interested parties to contact UE as soon as possible, with non-network proposals so that sufficient time is available to identify the preferred solution (be network, non-network or a combination) to address the network limitations identified in this DAPR. In the absence of any credible non-network solutions, UE identified lower-cost technically feasible network option becomes the preferred option. Indicative timeframes of the proposed network augmentations are provided in the Executive Summary.

UE’s Demand Side Engagement Document (DSED)2 has been developed to outline our process for engaging and consulting with interested parties, and for investigating, developing, assessing and reporting on non-network options as alternatives to network augmentation.

The information included in UE’s DSED:

Provides an overview of UE’s planning framework and approach to engage with interested parties for identifying viable non-network proposals to address network capacity limitations identified in this DAPR;

Describes how UE will maintain a Demand Side Engagement Register for parties wishing to be advised of relevant publications and events relating to UE’s planning activities;

Provides an outline of technical data requirements expected from non-network service providers when responding to a RIT-D consultation, and minimum criteria that non-network options should meet;

Describes the method adopted by UE to assess non-network options and negotiate services proposed by non-network service providers;

Describes the method used to determine the applicable non-network incentive payments; and

Provides a real example of UE’s non-network engagement.

A Demand Side Engagement Register has been established for customers, interested parties, industry participants and non-network service providers who wish to be informed of relevant publications and events relating to UE’s planning activities. Anyone who wishes to be included on our register should fill out details on our website at:

https://www.unitedenergy.com.au/contact-us/demand-side-engagement-registration/

2 UE: Demand Side Engagement Document. Available at:

https://www.unitedenergy.com.au/industry/mdocuments-library/



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3.2.3 Regulatory Investment Tests for Distribution

Under the national framework, UE must undertake a Regulatory Investment Test for Distribution (RIT-D) for network augmentation investments where the highest value of the credible option exceeds $5 million.3 The purpose of the RIT-D is to rank various distribution investment options and identify the preferred option (be it network, non-network or a combination) that maximise the present value of net economic benefit to all those who produce, consume and transport electricity in the National Electricity Market (NEM).

The RIT-D public consultation process involves three primary steps:

Publishing a Non-Network Options Report (NNOR);

Publishing a Draft Project Assessment Report (DPAR); and

Publishing a Final Project Assessment Report (FPAR).

This DAPR identifies network limitations that require detailed consideration under a RIT-D within the next 12 months. Upcoming RIT-D assessments are listed in Executive Summary.

3.2.4 Request for submissions

UE invites written submissions from interested parties to offer alternative proposals to defer or avoid the proposed network augmentations presented in Executive Summary. All submissions should address the technical characteristics of non-network options provided in this DAPR and include information listed in Section 5 of UE’s DSED.

All written submissions or enquiries should be directed to [email protected].

Alternatively, UE’s postal address for enquiries and submissions is:

United Energy

Attention: Manager Network Planning and Strategy

PO Box 449

Mt Waverley VIC 3149.

3 The purpose, principle and procedures of the RIT-D are set out in NER clause 5.17. The threshold value is varied from time to time by

the Australian Energy Regulator (AER).

mailto:[email protected]

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3.2.5 Joint planning

3.2.5.1 Victorian arrangements for transmission connection assets

Transmission connection asset planning is undertaken by UE, as a joint exercise, with other Victorian Distribution Network Service Providers (DNSP) and the Australian Energy Market Operator (AEMO), in its role as planner for the Victorian declared shared transmission network.

Transmission connection assets are those parts of the transmission system which are dedicated to the connection of customers at a single point. In Victoria:

The DNSPs have responsibility for planning and directing the augmentation of the facilities that connect their distribution systems to the Victorian shared transmission network.

AEMO is responsible for planning and directing the augmentation of the shared transmission network.

In accordance with clause 5.14.1(a)(1) of the NER, AEMO and the DNSPs undertake joint planning to ensure the prudent and efficient development of the shared transmission and the transmission connection facilities. To formalise these arrangements, AEMO and the DNSPs have agreed a Memorandum of Understanding (MoU) which sets out a framework for cooperation and liaison between the parties with regard to the joint planning of the shared network and connection assets in Victoria. The MoU sets out the approach to be applied by AEMO and the DNSPs in the assessment of options to address limitations in a distribution network where one of the options consists of investment in dual function assets or transmission investment, including connection assets and shared transmission network. The joint planning projects will be assessed by applying the appropriate investment test.

Further details of the joint planning arrangements relating to transmission connection assets are set out in the 2016 Transmission Connection Planning Report (TCPR), as explained in Appendix A.

3.2.5.2 Victorian arrangements for shared distribution assets

In accordance with clause 5.14.2 of the NER, UE undertakes joint planning with other DNSPs where there is a requirement to consider the need for any augmentations that affect the shared distribution network. Depending on the size of investment involved, a RIT-D may or may not be required. A lead party responsible for carrying out the RIT-D in respect to the joint planning project may be chosen, depending on the nature of the project. UE conducts joint planning and joint workings on network limitations with neighbouring DNSPs AusNet Electricity Services, Jemena and CitiPower.

The joint planning arrangements relating to the shared distribution systems are aimed at fostering the efficient and coordinated development of the distribution system. The joint planning projects will be assessed by applying the RIT-D in accordance with clause 5.17 of the NER.

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3.3 Significant changes from 2015 DAPR

3.3.1.1 Maximum demand forecast

In response to the ongoing uncertainty in the global and local economies, the latest maximum demand forecast for the UE service area has been revised downwards by the National Institute of Economic & Industry Research (NIEIR) compared to that published in the 2015 DAPR. This is reflected in the figure below.

Figure 1 – UE 10% PoE summer maximum demand forecasts

Table 2 summarises the change in UE’s 10% PoE summer maximum demand forecast.

Table 2 – Changes in UE’s 10% PoE summer maximum demand forecast

10% PoE Summer maximum demand 2016 Forecast 2015 Forecast Change

2016-2017 summer 2172 MW 2175 MW -0.1%

2020-2021 summer 2207 MW 2299 MW -4.0%

2025-2026 summer 2379 MW 2531 MW -4.1%

Ten-year average growth rate 1.1% pa 1.4% pa -0.3%

It is noted that under the latest forecasts, the maximum demand is still expected to increase over the planning period.

2100

2150

2200

2250

2300

2350

2400

2014 2015 2016 2017 2018 2019 2020 2021 2022

Maxim

um

Dem

an

d (

MW

)

Year

2014 Forecast 2015 Forecast 2016 Forecast

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3.3.1.2 Value of Customer Reliability (VCR)

The VCR used by UE to calculate the cost of expected unserved energy is provided by AEMO each year. Following a review of the national VCR, AEMO published the latest average Victorian VCR on 30 September 2014 as shown in the table above. The latest VCR was revised downwards from $63,090 per MWh to $39,500 per MWh (a reduction of approximately 40%). For the 2016 DAPR, AEMO’s current VCR has been escalated to 2016 dollars in accordance with the escalation method defined in AEMO’s Application Guide. VCR of $40,550 per MWh has been used for all electricity customers in UE’s service area.

3.3.1.3 Discount Rate

Following the AER’s final determination of UE’s 2016-2020 Price Review Proposal, a discount rate of 6.37% (real, pre-tax) has been adopted in undertaking the economic analysis, and calculating the annualised cost of augmentation in the 2016 DAPR. The discount rate used in the 2015 DAPR was 6.12% (real, pre-tax).

3.3.1.4 Timing of proposed network augmentations

The network limitation assessment and timing of network augmentations presented in this DAPR are based on UE’s 2015 maximum demand forecast, latest VCR and new discount rate. Given a nominal reduction in the maximum demand forecast compared with last year’s forecast and a slight change in VCR and the discount rate, the timing of network augmentations identified in this DAPR is expected to be either similar or deferred by one to two years on average compared to those published in the 2015 DAPR. Whilst lower growth is the case for the overall UE network, there remain pockets of strong growth within UE’s service area and these typically occur in the parts of our network that are currently operating well above the average utilisation. Therefore, the timing of our network augmentations has been determined on a case-by-case basis. Table 3 below summarises the change in timing of proposed major network augmentations.

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Table 3 – Changes in timing of proposed major network augmentations

Proposed network augmentation 2016 DAPR 2015 DAPR

East Burwood Supply Area:

Re-conductor SVTS-EB 66 kV line Dec 2017 Dec 2016

Notting Hill Supply Area:

Third transformer at Notting Hill (NO) zone substation4 Dec 2017 Dec 2017

Doncaster / Templestowe Supply Area:

Up-rate TSTS-DC No.1 66kV line and droppers Dec 2017 Dec 2019

Doncaster / Templestowe Supply Area:

Fourth transformer at Doncaster (DC) zone substation together with two new high-voltage distribution feeders

Dec 2019 Dec 2019

Lower Mornington Peninsula Supply Area:

Install new 66 kV line between Hastings and Rosebud zone substation5 Dec 2022 Dec 2020

East Malvern Supply Area:

Third transformer at East Malvern (EM) zone substation Dec 2022 -

3.4 Feedback on UE’s 2015 DAPR

The 2015 DAPR incorporated the feedback received from AER.

In February 2016, UE held a public forum to discuss the 2015 DAPR with the interested parties on UE’s Demand Side Engagement Register. In October 2016, UE engaged with the local council within UE’s service area at a Future Energy Planning forum organised by Northern Alliance for Greenhouse Action for all councils in Victoria. Feedback provided from this forum has been incorporated into the 2016 DAPR including new features in Google Earth geographic visualisation representation of UE’s network constraints.

3.5 DAPR structure

An outline of the content of each chapter of the DAPR is presented below.

Executive summary - provides the DAPR’s key messages.

Introduction - details UE’s obligations under the Distribution Planning and Expansion Framework and high level information about the contents of the DAPR. This chapter also summarises the significant changes from 2015 DAPR.

4 Following the conclusion of the RIT-D consultation process, this is now a committed project. Network solution has been recommended

as a preferred option in the Final Project Assessment Report published in December 2016. 5 Following the conclusion of the RIT-D consultation process, this is now a committed project. A non-network solution has been

contracted to defer this augmentation by two years.

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Network overview - provides an overview of UE’s operating environment and a detailed

view of the assets that make up the UE network, including the geographical network service area and the number and type of distribution assets.

Maximum demand forecast – presents the maximum demand forecasts and provides

information about the methods and assumptions upon which UE’s maximum demand forecasts are based.

Network development plan – provides information on UE’s:

o Annual planning review process, methods and assumptions upon which the future planning of UE’s network is based;

o Maximum demand forecasts including capacity of transmission-connections assets over a ten-year period. Transmission connection planning obligations of the DAPR are presented in the document titled “2016 Transmission Connection Planning Report” (Appendix A);

o Maximum demand forecasts including capacity of sub-transmission systems and zone substations over a five-year period;

o Maximum demand forecasts including capacity of high-voltage distribution feeders over a two-year period;

o Present and emerging network limitations including preferred network solutions to alleviate those limitations;

o Non-network solution requirements to defer or avoid the proposed network augmentations; and

o Projects that have been, or will be, assessed under the RIT-D.

Demand management activities – provides an overview of actions undertaken by UE to

promote non-network solutions. Non-network projects or initiatives that are currently underway are also provided.

Network performance – provides information on recent reliability and power quality

performance, including improvement initiatives planned for this planning period.

Asset management – provides an overview of UE’s approach to all aspects of asset

management including maintenance, inspection, renewal and refurbishment at a granular asset category level. The major renewal and refurbishment projects that are planned for the next five years are also included.

Metering and Information Technology – provides an overview of UE’s metering and IT

obligations and forecast capital investments in metering and Information Technology systems.

Abbreviations and glossary – provides abbreviations and glossary of terms referred to throughout the DAPR.

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Appendix A – Transmission Connection Planning – presents the transmission

connection planning obligations of the DAPR in the document titled “2016 Transmission Connection Planning Report”.

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4 Network overview

4.1 Overview of United Energy

UE is a regulated Victorian electricity distribution business with an electricity distribution network covering 1,472 square kilometres and serving approximately 664,550 customers throughout Melbourne’s south east and the Mornington Peninsula. UE’s service area is illustrated below.

Figure 2 – UE service area

UE’s service area is largely urban and semi-rural, and although geographically small (about one percent of Victoria’s land area), it accounts for around one-quarter of Victoria’s population and one-fifth of Victoria’s electricity maximum demand.

The northern part of UE’s service area is a leafy developed urban area lying entirely within metropolitan Melbourne, bounded by the AusNet Electricity Services and CitiPower service areas and Port Phillip Bay. The area includes predominantly residential and commercial centres such as Box Hill, Caulfield, Doncaster and Glen Waverley, and light industrial centres such as Braeside, Clayton, Heatherton, Mulgrave and Scoresby.

The central part of UE’s service area is a mix of developed and undeveloped land and includes the industrial and commercial centre of Dandenong being recognised as Victoria’s manufacturing heartland in the south-east of Melbourne. Dandenong and the adjacent suburb of Keysborough is UE’s largest growth area for new residential and industrial development.

Frankston denotes the southern rim of the Melbourne metropolitan area and is the gateway to the Mornington Peninsula. Frankston is one of the largest retail areas outside the Melbourne CBD. The Mornington Peninsula, in the southern part of UE’s service area, is a 720 square kilometre boot-shaped promontory separating two contrasting bays – Port Phillip and Western Port. The Mornington Peninsula is surrounded by the sea on three sides, with coastal boundaries of over 190 kilometres.

UE’s service area contains a number of major freeways including the Eastern, Monash, Eastlink, Peninsula Link and the Mornington Peninsula freeway, and railways including the Alamein, Dandenong, Frankston, Glen Waverley, Ringwood and Sandringham lines. These transport routes and the proximity of the area to the Melbourne CBD makes this part of Victoria an attractive location for residential, commercial and light industrial development, and recreational activities.

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UE’s electricity distribution assets within the service area have a replacement value of over four billion dollars and comprise of 47 zone substations, approximately 215,400 poles, 13,230 distribution substations, 10,100 km of overhead power lines and 2,800 km of underground cables.

4.2 Summer 2015-16 maximum demand

The actual coincident maximum electricity demand on UE’s distribution network for summer 2015-16 was 1,964 MW which occurred at 1630 AEST on 13 January 2016. This was 228 MW (13 percent) higher than the previous summer’s maximum demand of 1,736 MW. The weather conditions experienced on the day of the 2015-16 summer maximum demand were considerably hotter than the weather conditions experienced on the summer maximum demand day in 2014-15.

On the day of the 2015-16 summer maximum demand, the average ambient temperature was 30.6°C6 representing a 50% probability of exceedance (PoE)7, that is, this temperature is expected to be exceeded every two years.

On the day of the 2014-15 summer maximum demand, the average ambient temperature by comparison was 26.9°C corresponding to a 100% PoE.

The highest actual maximum demand experienced to date for the whole of UE’s network was 2,084 MW during summer 2008-09, at an average daily ambient temperature of 35.0°C corresponding to a 4% PoE.

The lower maximum demands over recent years can be attributed to the following.

Last year was an average summer with the temperature conditions on the day of the maximum demand having a 50% PoE.

In 2008-09, UE virtually had no solar photovoltaic embedded in our network. By 2015-16, this had reached an installed capacity of 147 MW. UE estimates that solar photovoltaic contributed to reducing the 2015-16 maximum demand by 29 MW.

While extreme weather conditions primarily determine maximum demand events, the maximum demand also depends on the level of commercial, educational and industrial sector activities prevailing at the time. These activities are typically lower during summer (school) holiday periods and only return to normal levels in late January / early February. The 2015-16 summer maximum demand occurred during the summer holiday period when many schools and businesses are still closed or operating at reduced levels than normal. Therefore, had a similar weather condition occurred in February, the level of maximum demand would have expected to be higher than the maximum demand observed on 13 January 2016.

6 Based on a Melbourne Olympic Park maximum daily temperature of 42.2 °C and an overnight minimum of 19.0 °C 7 Demand is sensitive to high ambient temperatures and in particular consecutive hot weekdays. To quantify the chances of demand

exceeding the load forecast one or more times in a given summer, a probability is assigned to the forecast. Load forecasts based on 10% PoE relate to the maximum average temperature conditions that would give rise to the demand being exceeded, on average, once every ten years. By definition therefore, the actual demand in any given year has a 10% chance of being higher than the 10% PoE

maximum demand forecasts. Similarly, load forecasts based on 50% PoE relate to the maximum average temperature conditions that would give rise to the demand being exceeded, on average, once every two years. For 2016-17, 10% PoE is defined as a 34.5°C average daily temperature at the Melbourne Olympic Park Weather Station based on 50 years of historical temperature data. The

corresponding 50% PoE is 31.5°C and the 90% PoE is 29.3°C.

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Retail electricity price rises over recent years has contributed to the dampening of growth in maximum demand. UE estimates that the elasticity of summer maximum demand to retail electricity price is approximately -0.11 percent.

UE is continuing to analyse major influences of maximum demand including economic drivers, population, climate conditions and any changes to energy usage behaviours as a result of electricity price changes, energy conservation or distributed generation and storage to understand:

The potential impacts on maximum demand and future network augmentation;

To help develop strategies to manage maximum demand into the future; and

To continually improve UE’s maximum demand forecasting accuracy.

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4.3 Assets covered

UE owns, manages and operates an extensive electricity distribution network that transports electricity from the high voltage transmission network to the premises of residential, commercial and industrial customers. UE is also responsible for planning and directing augmentations of the transmission connection asset facilities connecting the shared transmission network with the distribution network (refer to Figure 3).

UE’s distribution network is predominantly overhead and made up of a large number of interconnected assets of varying age and condition.

Figure 3 – UE distribution asset portfolio

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Table 4 provides a breakdown of UE distribution assets as at 31 December 2015.8

Table 4 – UE network parameters

Network parameters Statistics

Network service area 1,472 km2

Peak coincident demand9 1,964 MW

Record peak coincident demand10 2,084 MW

Total customers 664,550

Bulk supply points 11

Sub-transmission circuits 78

Zone substations 47

Major power transformers 112

Distribution transformers 13,230

Power poles 215,400

Overhead power lines

- Sub-transmission 615 km

- High voltage distribution 3,642 km

- Low voltage distribution 5,824 km

Underground power cables

- Sub-transmission 4 km

- High voltage distribution 1,054 km

- Low voltage distribution 1,736 km

4.3.1 Description of network assets

4.3.1.1 Terminal stations

UE takes bulk supply from the shared transmission network at eleven transmission connection points provided by nine terminal stations at 66 kV, two of which also provide supplies at 22 kV. The facilities that connect the distribution network to the high voltage transmission network are known as the transmission connection assets. These assets are owned, operated and maintained by AusNet Transmission Group, however, UE is responsible for planning and directing augmentations to the transmission connection assets. At seven of the eleven transmission connection points, supply is shared with other distribution businesses and therefore joint planning and risk sharing arrangements exist.

Table 5 presents the terminal stations that supply the UE distribution network.

8 UE: 2014 Regulatory Information Notice (RIN) 9 The actual maximum demand recorded on the UE network for summer 2015-16 10 The actual maximum demand recorded on the UE network for summer 2008-09.

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Table 5 – UE bulk supply points

Terminal station Abbreviation Supply voltage Shared supply

Cranbourne / Frankston CBTS / FTS 66 kV AusNet Electricity Services

East Rowville ERTS 66 kV AusNet Electricity Services

Heatherton HTS 66 kV No

Malvern MTS 66 kV No

Malvern MTS 22 kV No

Richmond RTS 66 kV CitiPower

Ringwood RWTS 66 kV AusNet Electricity Services

Ringwood RWTS 22 kV AusNet Electricity Services

Springvale SVTS 66 kV CitiPower

Templestowe TSTS 66 kV AusNet Electricity Services, CitiPower, Jemena

Tyabb TBTS 66 kV No

4.3.1.2 Sub-transmission systems

The UE sub-transmission system consists of overhead power lines and underground cables operating at 66 kV and some 22 kV, to transport bulk electricity from terminal stations to zone substations located throughout UE’s service area. The sub-transmission circuits are generally arranged in looped and meshed systems to enable the connected zone substations to continue to operate at full supply for most of the time with the loss of any single circuit.

Table 6 – UE sub-transmission systems

Sub-transmission system Supply voltage Shared supply

CBTS-CRM-LWN-FTN-FTS-CBTS 66 kV No

ERTS-DN-HPK/DSH-DVY-ERTS 66 kV AusNet Electricity Services

ERTS-LD-MGE-ERTS 66 kV No

HTS-KBH-M/MC-BR-HTS 66 kV No

HTS-MR-BT-NB-HTS 66 kV No

HTS-HT-CM-SR-HTS 66 kV No

MTS-BW/SH-MTS 22 kV No

MTS-CFD-EL-EM-MTS 66 kV No

MTS-OAK-OR-MTS 66 kV No

RTS-EW-SK-RTS 66 kV CitiPower

RTS-K-CL-RTS 66 kV CitiPower

RWTS-BH-NW-RWTS 66 kV No

SVTS-OE-CDA-SVTS 66 kV No

SVTS-EB-RD-SVTS 66 kV CitiPower

SVTS-GW-NO-SVTS 66 kV No

SVTS-SS-NP-SVTS 66 kV No

SVTS-SV-SVW-SVTS 66 kV No

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Sub-transmission system Supply voltage Shared supply

TBTS-DMA-TBTS 66 kV No

DMA-RBD-DMA 66 kV No

RBD-STO-RBD 66 kV No

TBTS-FSH-MTN-TBTS 66 kV No

TBTS-HGS-TBTS 66 kV No

TSTS-BU-WD-TSTS 66 kV No

TSTS-DC-TSTS 66 kV No

4.3.1.3 Zone substations

The UE network has a total of 47 zone substations11 where the voltage is converted from sub-transmission voltages (66 kV and 22 kV) to distribution voltages (22 kV, 11 kV and 6.6 kV). These zone substations are generally arranged in a fully switched configuration with one, two or three transformers to provide a high level of reliability. Zone substation configurations vary from outdoor types to fully enclosed arrangements. They comprise sub-transmission circuits, sub-transmission switchgear, power transformers and distribution switchgear.

Table 7 – UE zone substations

Zone substation Abbreviation Transformation Shared supply

Box Hill BH 66/22 kV No

Beaumaris BR 66/11 kV No

Bentleigh BT 66/11 kV No

Bulleen BU 66/11 kV No

Burwood BW 22/11 kV No

Clarinda CDA 66/22 kV No

Caulfield CFD 66/11 kV No

Cheltenham CM 66/11 kV No

Carrum CRM 66/22 kV No

Doncaster DC 66/22 kV No

Dromana DMA 66/22 kV No

Dandenong DN 66/22 kV No

Dandenong South DSH 66/22 kV No

Dandenong Valley DVY 66/22 kV No

East Burwood EB 66/22 kV No

Elsternwick EL 66/11 kV No

East Malvern EM 66/11 kV No

Elwood EW 66/11 kV No

Frankston South FSH 66/22 kV No

Frankston FTN 66/22 kV No

11 Keysborough (KBH) zone substation was commissioned for summer 2014-15.

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Zone substation Abbreviation Transformation Shared supply

Glen Waverley GW 66/22 kV No

Hastings HGS 66/22 kV No

Heatherton HT 66/22 kV No

Gardiner K 66/11 kV CitiPower

Keysborough KBH 66/22 kV No

Lyndale LD 66/22 kV No

Langwarrin LWN 66/22 kV No

Mentone M 66/11 kV No

Mordialloc MC 66/22 kV No

Mulgrave MGE 66/22 kV No

Moorabbin MR 66/11 kV No

Mornington MTN 66/22 kV No

North Brighton NB 66/11 kV No

Notting Hill NO 66/22 kV No

Noble Park NP 66/22 kV No

Nunawading NW 66/22 kV No

Oakleigh OAK 66/11 kV No

Oakleigh East OE 66/11 kV No

Ormond OR 66/11 kV No

Rosebud RBD 66/22 kV No

Surrey Hills SH 22/6.6 kV No

Sandringham SR 66/11 kV No

Springvale South SS 66/22 kV No

Sorrento STO 66/22 kV No

Springvale SV 66/22 kV No

Springvale West SVW 66/22 kV No

West Doncaster WD 66/11/6.6 kV CitiPower

4.3.1.4 High voltage distribution feeders

UE’s high voltage distribution feeders operate radially at 22 kV, 11 kV and 6.6 kV and distribute electricity from zone substations to local distribution substations. The distribution feeders in UE’s urban and semi-rural areas have a high level of interconnectivity with neighbouring feeders through normally open switches and provide considerable flexibility during contingency events. Rural areas are predominantly supplied by overhead spur feeders with limited interconnectivity which could compromise the supply under contingency events.

Figure 4 illustrates the location of UE bulk supply points, zone substations and sub-transmission systems. Figure 5 illustrates the geographical area serviced by each zone substation.

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Figure 4 – UE bulk supply points, zone substations and sub-transmission systems (schematic view)

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Figure 5 – UE zone substation supply areas

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4.3.1.5 Distribution substations

Distribution substations convert the distribution high voltage (22, 11 or 6.6 kV) to low voltage (400/230 V) for use by the majority of UE customers. Distribution substations can either be an indoor substation (located within a building), a kiosk substation, a ground-type substation or a pole substation.

4.3.1.6 Low voltage network

The low voltage network delivers electrical energy at 400/230 V from the local distribution substation to the customers’ service lines. The low voltage network is relatively short because of voltage drop and consequent supply quality limitations. The majority of the low voltage network is of overhead construction however reticulations to new residential housing estates are underground.

4.3.1.7 Service lines

Service lines are a major subset of the assets that make up the distribution network. The service connection is the point at which the customers’ installations interact with the UE distribution network. Each customer within our service area has a service connection from the overhead or underground low voltage network.

4.3.1.8 Communications network

The groups of assets that comprise the communications infrastructure include overhead and underground copper supervisory cable systems, fibre-optic cables, wireless communications systems and services, leased telecommunications services, and associated hardware and software. These assets facilitate the remote control and monitoring of the network and the operation of complex network protection systems.

4.3.1.9 Meters

UE as a Local Network Service Provider (LNSP) has an obligation to provide metering to all customers within our service area. Currently, customers who consume greater than 160 MWh per annum can choose a meter provider. However, UE is the meter provider for those that do not choose an alternative meter provider and for all customers that consume less than 160 MWh per annum. Metering assets include direct connected meters, instrument transformer connected meters and the associated current and voltage instrument transformers. Smart interval meters have been rolled out to essentially all of our customers consuming less than 160 MWh as part of the Advanced Metering Infrastructure (AMI) programme.

For further details on AMI programme, please refer to Section 10.1.

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4.3.1.10 Asset management information systems

Asset Management information systems have been implemented at UE to support the Asset Management processes. The information systems include:

Geographical Information System (GIS)

Asset Management System (AMS) provides an integrated and structured approach to guide the development, coordination and execution of asset creation and maintenance activities to optimise the lifecycle costs, risk, performance & opportunities

Works Management, Maintenance and Logistics (SAP)

SCADA, Outage Management and Distribution Management Systems (OMS/DMS)

Network Load Management System (NLM)

Document Management (SharePoint)

Power quality database (ION Enterprise)

Real-time data historian (OSI PI)

Ratings & Loadings database

Power flow simulation models (PSSE/PSSU/PSS Sincal)

Maximum demand simulation models (eViews)

Asset management, models, tools and databases

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4.4 Operating environment

UE operates in an environment where economic growth, population growth, price and increased penetration of temperature sensitive loads influence growth in maximum demand. UE also operates within the constraints of a regulatory environment determined by the National Electricity Rules (NER) and therefore our network planning is governed by the Distribution Planning and Expansion framework as prescribed in Chapter 5 Part B of the NER.

4.4.1 Factors influencing maximum demand

Economic growth, population growth and increased penetration of temperature sensitive load such as air-conditioning units over the last 20 years have been the major drivers for maximum demand growth in the UE service area. Slowing of maximum demand growth in recent years has been primarily attributed to electricity price rises, a slowing of the economy, and to a lesser extent, the impact of solar photovoltaic installations and customer-implemented energy efficiencies.

A number of potentially significant developments are occurring in the way customers use their electricity and the way electricity is priced. These developments will ultimately have a measurable impact on UE’s maximum demand growth. Increased use of distributed embedded generation through reduced technology cost and increased environmental awareness is already being experienced with roof-top solar photovoltaic panels. Also on the horizon are potentially significant uptakes of electricity storage and electric vehicle technologies. These changing drivers of demand and energy are incorporated in UE’s maximum demand forecasts. Therefore, the network limitation assessment and timing of preferred network solutions identified in this DAPR reflects the changing environment in which UE operates.

4.4.1.1 Economic growth

UE engages the National Institute of Economic and Industrial Research (NIEIR) each year to provide a whole-of-UE service area maximum summer and winter demand forecast for ten years. NIEIR prepares the forecasts on a low, base (expected) and high macro-economic growth basis. These demand scenarios are considered in detailed assessments such as UE internal business case or Regulatory Investment Test for Distribution (RIT-D) to identify the preferred investment that maximise the present value of the net market benefit.

Total gross regional product (GRP) for the UE region is expected to rise by an average rate of 2.0 percent between 2017 and 202712. The inner suburbs of Melbourne in UE’s service area are experiencing high rates of economic growth due to their access to infrastructure, such as transport, health and education, as well as major shopping centres and high-rise, high density building developments.

The ongoing uncertainty surrounding the global and Australian economies is likely to have an ongoing dampening effect on electricity demand growth. While the Australian economy has proven to be fairly resilient to international pressures since the global financial crisis, there has been a slowdown in the mining and manufacturing sectors with weaker commodity prices and recent large factory closures which are having flow-on effects to the rest of the Australian economy.

12 Source: NIEIR 2016-2017 MD Forecast Report

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4.4.1.2 Population growth

Total population in the UE region represents 23.6 percent of Victoria’s population and 23.6 percent of Victoria’s dwelling stock13. UE region population is expected to increase steadily over the projection period. Under the base scenario, an average annual population growth rate of 1.2 percent is projected for the UE region between 2017 and 2027 compared to 1.4 percent average for Victoria. The strongest increase in population over the 2017 to 2027 period is expected in the South East Inner Melbourne and Southern Outer Melbourne suburbs within UE’s service area (1.5 percent per annum). Population growth is expected to remain modest in the other areas of UE’s service area.

Urban infill and apartment construction is impacting on many areas within UE’s service area as a result of changes to planning regulations and strong underlying demand for dwellings within 20 kilometres of the Melbourne CBD. The total dwelling stock within the UE region is forecast to grow by an average rate of 1.0 percent between 2017 and 2027 under the baseline scenario. The strongest percentage increases in the dwelling stock are expected in the South East Inner Melbourne area. The total stock is expected to increase by an average rate of 1.2 percent between 2017 and 2027 in the South East Inner Melbourne region.

4.4.1.3 Price

Increasing retail electricity prices (in real terms) over recent years has put downward pressures on maximum demand growth within the UE supply area. However current tariff structures mean that higher prices principally affect energy consumption more than maximum demand. UE customers implementing energy efficiency, reduced energy consumption and distributed generation in response to price have a much bigger impact on annual energy consumption than it does on maximum demand. Nevertheless, the impact of price is significant and is explicitly modelled in the macro-economic maximum demand forecasting model.

4.4.1.4 Temperature sensitive loads

Over the past decade there has been a trend of divergence between average demand (energy) and weather-corrected maximum demand, with maximum demand the principal driver of network reinforcement investment. Maximum demand growth exceeding energy growth has been anecdotally attributed to the growing affluence of the average electricity consumer who is increasingly installing energy intensive devices such as air conditioning. Air conditioning has had a significant impact on the UE summer maximum demand to the point where virtually all areas of the network are now peaking in summer. Our network limitations therefore are generally related to thermal capacity of plants in summer where network loading is at its highest and the rating of the network assets is at its lowest. More recently, declines in load factor are also being attributed to reducing energy consumption though the increased installation of roof-top solar photovoltaic panels, energy efficiency and energy conservation actions from customers.

The penetration of space cooling equipment has increased dramatically in UE’s service area over the last 20 years reflecting:

The impact of a number of very hot summers (between 1997 and 2010, and in 2014) on discretionary purchases of space cooling equipment;

13 Source: NIEIR 2015-2016 MD Forecast Report

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Improved marketing penetration and technological advances in space cooling equipment;

The coincident increase in construction activity in both the commercial and residential sectors. The increase in townhouse and especially apartment construction for residential dwellings are particularly suited to reverse cycle air-conditioning units (heat pumps); and

The continued ageing of the population and the associated expansion in retirement villages for senior persons.

For the UE summer maximum demand, which typically occurs between 4:00 to 6:00 p.m. (summer time) on a weekday in January or February, the temperature sensitive load or additional demand is unambiguously associated with cooling appliances such as air conditioners, refrigeration units and fans. The figure below shows total temperature sensitive load for the UE region from 2000-01 to 2015-16. This effectively represents total installed capacity for the UE region. This data was estimated by NIEIR from actual sales of air conditioning equipment in Victoria, energy efficiency indices including Minimum Energy Performance Standards (MEPS), and half hourly electricity demand data. Total temperature sensitive load installed in the UE region has risen from around 730 MW in 2000-01 to over 1,330 MW in 2015-16.

Figure 6 – Total summer temperature sensitive load for UE14

4.4.1.5 Energy efficiency

Improved standards in air-conditioning efficiency (MEPS) can lead to reductions in the rate of increase of maximum demand as more efficient air-conditioners and other household appliances are purchased over time for new stock and replacement of existing installed stock. However, the impact of energy efficiency policies on UE’s maximum demand is expected to remain relatively small over the forecast period.

14 Source: NIEIR

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4.4.1.6 Distributed generation

Over the last several years, an increased use of distributed embedded generation was experienced with roof-top solar photovoltaic panels connected to UE’s network. These generators are catered for in UE’s demand forecasts as negative loads because of net metering used in UE’s service area for residential roof-top solar photovoltaic panels. Hence the level of uptake of micro-generators has a downward influence on UE’s growth in maximum demand. UE incorporates the uptake of micro-generators into the maximum demand forecast.15

During the 2015-16 summer, the UE network had approximately 147 MW of installed roof-top solar photovoltaic panels connected to the system. It is assessed that the contribution of this generation to reducing the UE maximum demand last summer was approximately 29 MW.

The PV take-up rates in the UE distribution region have fallen over the past two years however this is offset somewhat by larger systems being installed. This reflects a number of factors, including the abolition of RET multipliers, lower feed-in-tariffs, and a curtailment in the fall in installed costs. Monthly installation rates in the UE distribution area were over 800 systems in 2011-12, around 500 in 2013-14, and around 415 in 2015-16. For the Base scenario, the average monthly PV installation rate within UE network is forecast to be 625 per month in 2016-17, falling to 460 per month by 2020-21 and 410 per month by 2026-27.

4.4.1.7 Demand management

Smart meters that have been rolled out across the UE service area have the potential to enable customers to actively participate in the management of their energy use through the provision of timely, relevant information and control options. Smart meters give the ability to apply enhanced tariff arrangements, energy management, customer signalling and more sophisticated power usage monitoring. The outcomes of the Australian Energy Market Commission’s (AEMC) Power of Choice review should provide customers with more opportunities to make informed choices about the way they control their demand and provide the lowest cost combination of demand and supply side options over the long term.

The Demand Management Incentive Scheme (DMIS) has encouraged distribution businesses to trial non-network alternatives or to manage the expected demand for standard control services in alternative ways. For the 2011-2015 regulatory control period, UE was allocated $400k pa in the AER’s EDPR determination ($2M over five years) as an ex-ante allowance under the Demand Management Innovation Allowance (DMIA). UE spent this full allocation by the end of that regulatory period on the following three projects:

Doncaster Hill District Energy Services Scheme (DESS)

Virtual Power Plant (VPP) Pilot

Bulleen Demand Response (Summer Saver) Pilot

The distribution planning and expansion framework is also encouraging distribution businesses to proactively consult with non-network service providers to identify economically feasible alternative solutions to network augmentation. In the last three years, UE has established Memorandum of Understanding (MoU) with several non-network service providers to undertake joint planning to identify viable alternative solutions. This working arrangement has resulted in the identification of

15 The uptake of micro-generators is considered by NIEIR in developing the maximum demand forecasts for UE

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a number of economic demand management solutions, as a deferral option to distribution augmentation. UE currently has one network support agreement in place with a third-party to defer network augmentation.

For further details on our demand management plans, please refer to Section 7.

4.4.1.8 Distributed storage

Distributed storage solutions are predicted to become economic in a small number of constrained areas of UE’s network over the next year. Commercialised products for use at the household, business or precinct level are likely to become economically viable on a larger scale in the next 5 to 10 years.

When distributed storage becomes economic, customers may seek to install battery storage coupled with solar photovoltaic. It is expected that 5 percent of new PV installations in UE network in 2017-18 will have battery storage. This take up rate rises 5 percent per annum until 2024-25 when 40 per cent of new solar systems come equipped with battery backup. These systems could provide flexibility for UE to use the stored energy during critical peak demand conditions to support constrained areas of the distribution network. It would also allow our customers to take advantage of time-of-use tariffs. To this end, UE is in the final stages of exploring the economics and technical viability of storage at the household level with its Virtual Power Plant (VPP) project. Storage coupled with solar photovoltaic could be a viable way to address immediate capacity shortfalls and defer network augmentations.

4.4.1.9 Electric Vehicles

Plug-in Hybrid Vehicles (PHEV) and Battery Electric Vehicles (BEV) is an emerging technology which has attracted a significant amount of interest over recent years. Hybrid electric vehicles have been available since the early 2000s and combine the use of an internal combustion engine as well as an electric engine for propulsion. PIHV and BEV are able to charge their batteries by plugging into electric supply. PIHVs have become commercially available in Australia since 2012. In the last year, approximately 1,650 plug-in EVs were sold Australia wide which is 0.14 percent of total vehicles sold within Australia. The on-road EVs are currently made up of around 60 percent plug-in hybrid vehicles, and 40 percent battery electric vehicles.

The current cost of storage is approximately $450 USD per kWh (based on estimates) or around $350 USD per kWh based on reported numbers by Nissan and Tesla. The market leading Tesla could reduce these costs to $175 USD per kWh through improvements in technology and economics of scale with the completion of company’s “Gigafactory” facility. Tesla commenced production from this facility at the end of 2015, and target a production of 500,000 units by 2020.16

EVs are designed to be connected to the electricity distribution network for charging / discharging. The timing of charging is crucial for network investment decisions. Therefore, network price signals would play a key role in encouraging EV charging behaviours during off-peak demand conditions. Otherwise, EVs may be charged in the late afternoon when drivers return home from work. This behaviour would correspond with the timing of existing household air-conditioning loads and add to increase the maximum demand.

16 http://nextbigfuture.com/2015/07/tesla-gigafactory-on-track-to-begin.html

http://nextbigfuture.com/2015/07/tesla-gigafactory-on-track-to-begin.html

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In addition to charging behaviour, clustering of EVs and their uptake rates are of importance to UE. To this end, models have been developed to assess the uptake rates of EVs within UE’s service area by examining the economic viability of EV against traditional internal combustion engine vehicles.17 It is anticipated that PEV sales will account for around 12.6 per cent of total sales by 2027. In Victoria, annual sales are expected to increase from around 800 in 2016 toward 48,000 per annum by 2027. The fleet of Victorian plug-in electric vehicles on road is likely to reach 185,000 by 2027, from a negligible amount on roads in 2015. PEV’s are assumed to have an average life of around 10 years.

4.4.2 Network utilisation and load factor

UE’s electricity distribution network is augmented based on a probabilistic planning approach where the cost of power supply interruptions, taking into account the probability of plant outages, load transfer capability to neighbouring network, plant ratings and demand profiles, is assessed against the annualised cost of a network augmentation. When the annualised cost of power supply interruption to customers exceeds the annualised cost of augmentation, the augmentation becomes economically viable. This approach means that where redundancy is provided, plant is loaded above its firm (N-1) rating to achieve some level of load-at-risk before an augmentation becomes economic. UE measures this level through the network utilisations which are calculated based on the maximum demand divided by the 24-hour limited cyclic (N-1) rating for the asset, or in the case of radial assets (i.e. high-voltage distribution feeders), the cyclic (N) rating.

Figure 7 – UE asset utilisation

To understand the utilisation of the asset base for periods other than at the maximum demand, the network load factor measure describes the ratio of the average annual demand18 to the maximum

17 The models used by UE were developed by Acil Allen Consulting and NIEIR in 2014. 18 Annual energy purchases divided by 8766 hours per annum.

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demand. It is important to note that maximum demand rather than energy consumption is the key driver for network investment, particularly where, as in UE’s case the weather-corrected annual load factors have shown a decrease over time as shown in Figure 8.

Figure 8 – UE Network Weather-corrected load factor

The load factor is a good indicator of the variability of the demand throughout the year. A low load factor means there is less energy supplied per unit of demand supplied, and therefore a greater divergence between the average demand and the maximum demand. The decreasing load factor is mainly attributed to the growing penetration of temperature sensitive, energy intensive loads such as air-conditioning units, and increasing implementation of roof-top solar photovoltaic panels and energy-efficiency initiatives.

4.4.3 Weather-corrected maximum demand

The variability in the weather can have significant impacts on the actual recorded maximum demands year on year. This variability has been observed especially in recent years. To assess the underlying growth trend, weather-probabilities are assigned to maximum demand forecasts and weather-correction is undertaken on maximum demand actuals. This allows a direct comparison to be made between forecasts and actuals by normalising the impact of hot weather. A detailed description of the weather-correction process is provided in Section 5.2.2.

Historic forecasts and weather-corrected actuals, and forecasts of UE’s service area summer maximum demand for the base (expected) economic growth scenario is presented below.

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Figure 9 – UE Summer Maximum demand - base economic growth scenario19

Growth in UE’s 10% PoE summer maximum demand is expected to be 1.1 percent per annum over the next ten years.

4.4.4 Asset age and condition

The age profile of UE’s distribution network reflects the large investment that took place in the electricity networks in Victoria with much of the area electrified post-World War. Assets on the UE network were first installed in Melbourne in the early part of 1900s although it wasn’t until the late 1930s that network assets were being installed in large numbers. From the late 1950s the network started growing rapidly, with a large number of new customer connections driven by the economic growth in the post-war decades. During the latter part of the century the capacity of the network continued to grow as air conditioners, new developments, computers and other household appliances drove significant demand growth across the network. Much of this area is now urbanised. The present implication is that an increasing number of assets are approaching their end-of-life and require replacement over the current planning period.

The growing proportion of aged assets reflects the uneven historical development of the network, particularly in the 1960s and 1970s. The relationship between asset age and the probability of asset failure is well known. Assets typically have a long period of serviceable life with negligible failures, followed by a period of deterioration leading to increasing failure. This observation is reflected in the Weibull probability density function, an example of which is set out below.

19 The weather-corrected data series represent the maximum demand that would have occurred for a 50% PoE hot summer day based on the observed actual maximum demand. This data series is calculated by UE and is used for verifying the NIEIR forecast.

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Figure 10 - Typical Weibull distribution for an asset with 55 years of expected life

The failure characteristics will differ across asset categories. However, the key observation is that asset failure rates typically accelerate as assets approach their end of life. If an increasing proportion of assets are approaching end of life, the risk of asset failures across the network increases. As a prudent network company, UE anticipates and manages this risk. Figure 11 below summarises that 17 percent of our assets were at 85 percent or more life-expired in 2009 compared to 12 percent in 2009. The change in assets at high risk of failure (HROF) for UE network was forecast to be 19% in 2015, increasing to 28.1%, or around $800M by 2020. UE’s overall strategy is to maintain reliability and network safety efficiently by complementing asset replacement with other strategies. This includes initiatives to improve asset inspection and condition monitoring to enable assets to be replaced as close as possible to their end of life (ideally just before imminent failure). It also includes initiatives focused on specific aspects of reliability and network safety. Reliability and network safety can be maintained efficiently with a somewhat modest increase in both asset replacement capex. However, if future asset replacement remains unchanged from recent historical levels, the proportion of assets approaching end of life would increase to 23.8 percent, which is an unacceptably high percentage from a risk perspective.

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Figure 11 - Assets reaching the end of their life – whole network

For further details on UE Asset replacement projects, please refer to Section 9.2.

4.4.5 Fault level

Switchgear, plants and lines in an electrical network have a maximum allowable short-circuit fault rating capability. UE estimates the prospective short-circuit fault level throughout its network to ensure it is within the limits set by the Victorian Electricity Distribution Code (and within the allowable limits of the installed electrical equipment). Table 8 shows the maximum allowable short-circuit fault levels (by voltage).

Table 8 – Distribution fault level limits for UE Network

Voltage (kV) Allowable fault level limit (MVA) Allowable fault level limit (kA)

66 2,500 21.9

22 500 13.1

11 350 18.4

6.6 250 21.9

<1 36 50.0

Out of various technically feasible fault level mitigation options available, UE primarily adopts six options, as appropriate, to manage the fault levels in the network. They are:

Replacing fault-limited equipment with higher rated equipment;

Leaving bus ties open to reduce the number of transformers operating in parallel;

Installing neutral earthing resistors (NER) at zone substations;

Installing higher impedance transformers;

Installing fault limiting reactors; and

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Implementing sequential switching schemes.

Depending on the specific circumstances, the most appropriate solution is selected to mitigate any identified fault level violations in the network. Embedded generators have the potential to add to the existing fault levels. UE therefore, closely assesses fault level contributions from embedded generators as part of the generator connection process to ensure fault level limits are not exceeded on any part of our network.

UE annually assesses maximum fault levels at zone substation 22, 11 & 6.6 kV buses and maximum fault levels for all UE sub-transmission network 66 kV buses to ensure that their maximum short-circuit levels remain within the limits set by the National Electricity Rules, the Use of System Agreements (UoSA) at the transmission connection points and for plant (e.g. circuit breaker) capabilities. Table 9 below provides information relating to the UE network short-circuit current limitations over a five-year outlook period and a recommended plan to manage the fault level within the required limits.

Table 9 – UE network buses with maximum fault level constraints (2017-2021 period)

Bus Name Short-circuit

Level (kA) Short-circuit

Limit (kA) Management Plan

Carrum 22kV 12.7

(1ph-g) 13.1

(NER)

The proposed Skye (SKE) zone substation and 66kV sub-transmission in 2020 may result in fault levels increase at CRM 22 kV buses which may exceed the minimum limits. A neutral earthing resistor may be required as part of this development.

Dandenong South 22kV 15.2 (3ph)

13.0 (CB)

A Bus Tie Open Scheme (BTOS) is in place to manage fault levels at DSH 22 kV. It is recommended to install a 66kV circuit breaker.

Doncaster 22kV 12.7

(1ph-g) 13.1

(NER)

The proposed installation of 4th transformer at Doncaster zone substation (DC) in 2019 will increase the fault levels above the required limits. It is recommended to install a neutral earthing resistor if a 4th transformer is installed.

East Rowville B12 and B34 66kV

23.9 (3ph)

23.4 (UoSA)

Following the installation of the fourth East Rowville 220/66 kV transformer in 2011-12, the normally open East Rowville 66 kV bus tie No. 2 to No. 3 or No.1 to No. 4 circuit breaker is closed for the outage of B2 Transformer resulting into high fault levels. This fault level is calculated considering motor contribution at DSH and transformer outage at ERTS. Implementation of BTOS at DSH will reduce the fault level.

Mentone 11kV 18.2 (3ph)

18.4 (NER)

It is considered a future constraint and require monitoring and re-assessment when there is committed network development plan that may increase the fault levels in the Mentone supply area.

North Brighton 18.0 (3ph)

18.0 (CB)

North Brighton 22kV switchboard will be replaced with higher fault capabilities by 2017.

Notting Hill 22kV 12.4

(1ph-g) 13.1

(NER)

The proposed installation of 3rd transformer at Notting Hill zone substation (NO) in 2018 will increase the fault levels above the required limits. It is recommended to install a neutral earthing resistor if a 3rd transformer is installed.

Ringwood 22kV 13.5

(1ph-g) 13.1

(NER)

The risk of the high fault levels is mitigated through the series reactors that are installed at the beginning of the 22kV distribution feeders. There is no existing risk on the downstream assets of the Ringwood 22kV supply area. The RWT 22 kV bus and switchgear is rated to

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Bus Name Short-circuit

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Limit (kA) Management Plan

26.2kA, well above the current fault level.

Sandringham 11kV 14.3

(1ph-g) 13.1 (CB)

A project is underway to implement sequential switching on the Sandringham 11kV bus, as an interim solution, to reduce high fault levels In 2020, it is proposed to replace the 11kV switchboard.

Springvale 22kV and Springvale West 22kV

12.9 (3ph)

13.1 (NER)

This constraint only occurs under rare switching conditions. UE will closely monitor the fault levels at these 22 kV buses and propose fault level management measures when these fault levels exceed 13.1kA

West Doncaster 11kV 18.6

(1ph-g) 18.4 (CB)

It is recommended to install a neutral earthing resistor to reduce the existing line to ground fault level. It is recommended to align this requirement with the transformer replacement project proposed in 2018.

UE is monitoring the take up of large scale solar technology and its impact on fault levels to determine the capital requirements for fault level management.

4.4.6 Quality of Supply (QoS)

UE is required to provide the quality of supply to all customers, compliant with limits established by the Victorian Electricity Distribution Code (the Code), National Electricity Rules, relevant Australian and UE standards, and good industry practice.

Clause 4.9 of the Code specifies that UE must monitor the quality of supply in accordance with the principles applicable to good asset management as contemplated by Clause 3.1 of the Code. Clause 4.2 of the Code specifies the minimum monitoring requirements for power quality monitoring as below:

Steady-state voltages and variations of the voltage at each zone substation in its distribution system which are outside the limitations specified in Clause 4.2.2; and

Steady-state voltages and variations of duration of more than 1 minute which are outside the range of steady-state voltages specified in Clause 4.2.2 at the extremity of one feeder supplied from each of those zone substations.

Moreover, Clause 9.1.5 of the Code specifies that UE must provide quality of supply information to customers or retailers about a connection. This information would either be provided from direct measurement, an extrapolated calculation from a remote measurement location or a system quality of supply minimum standard.

UE regards a proactive approach to power quality monitoring as an essential activity for detecting or foreseeing power quality disturbances on the distribution network. This is achieved by using a system of sophisticated power quality analysers located at strategic points across the network. Currently, every UE zone substation has at least one power quality monitoring device permanently installed on site. A power quality monitoring device is also installed at the far end of one feeder emanating from each zone substation, usually the longest feeder. These systems record the following information:

Steady-state and Transient voltages;

Under / over voltages;

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Voltage sags, swells and unbalance; and

Harmonics.

Power quality monitoring has revealed that in some instances power quality levels are identified as being outside the regulatory limits. Power quality projects are initiated to maintain current performance and prioritise the power quality issues experienced by the worst served customers. This may involve for example implementing bus-tie open control schemes to isolate the healthy parts of the network from faulted parts, installing harmonic filters to improve the harmonic content of the supply voltage, adjusting the tap position at the distribution substation, load balancing or installing low voltage regulators to provide compliant voltages to our customers.

UE, via the AMI metering data, has identified that there are a number of LV customers experiencing steady-state over-voltages. This issue was previously unknown due to the absence of continuous voltage monitoring on the low voltage network. Programmes are now in place to address these issues. For MV sites, voltage unbalance and voltage harmonics are the most prominent issues on the UE network.

For further details on our power quality performance and management, refer to Section 8.2.3.

4.4.7 Extreme Weather

Extreme weather events can have an adverse impact on UE’s network performance. Over the last 10-years, UE has experienced a number of extreme events during this time leading to poor performance of the network as a result of extreme temperatures, wind and drought.

This will have a notable impact on the UE network over the long-term, affecting asset performance (both short-term performance, as assets break down in extreme heat, and long-term performance, with over used or dry assets reaching their “end of life” earlier than expected). UE has recognised the impact of extreme weather events on network performance, and has adopted an objective to maintain network performance over the long term through an effective and targeted capital works programme to improve network resilience.

4.4.8 Regulatory environment

UE is subject to a range of legislative and regulatory obligations to ensure the distribution network remains safe, and is prudently and efficiently planned, constructed, operated and maintained, and ensuring prices charged for services are appropriate. These obligations are overseen by:

The Australian Energy Regulator (AER)

Energy Safe Victoria (ESV)

Essential Services Commission (ESC)

The Australian Energy Market Operator (AEMO)

The Australian Energy Market Commission (AEMC)

Energy and Water Ombudsman Victoria (EWOV)

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5 Maximum demand forecast

Maximum demand forecasting is a key component of the network planning and development process as it is used to determine emerging network limitations and timing for augmentations based on credible growth scenarios. Maximum demand forecasting can be challenging due to its dependency on a number of factors such as retail electricity prices, economic growth, population growth, weather patterns, solar photovoltaic panel installations, government energy or climate policies that encourage energy efficiency, and demand management.

In UE’s service area, it is the summer maximum demand relative to the summer equipment ratings that constrains the capability of the UE distribution network assets. Given the high dependency of maximum demand on economic conditions and ambient temperature, UE’s maximum demand forecasts are developed under three economic scenarios and three ambient temperature conditions. UE’s demand-related capital expenditure is directly related to the forecast maximum demand, therefore prudent network planning requires reliable maximum demand forecasts derived and reconciled using appropriate forecasting models.

5.1 Maximum demand forecast method

UE prepares three independent sets of maximum demand forecasts annually, a bottom-up spatial forecast and two top-down service area forecasts - one is internally generated using a model developed for UE by AECOM, and the other is provided to UE by the National Institute of Economic and Industry Research (NIEIR). The three forecasts are then reconciled to produce a consistent set of forecasts for the UE service area and at each of the network asset levels. The three forecasts are described in detail below:

UE’s bottom-up spatial maximum demand forecasts are based on trends identified by looking at localised historical data and future drivers that influence demand across all customer classifications. These drivers include local information such as proposed major industrial and commercial developments, predicted housing developments, proposed embedded generation, economic growth and known reductions in customer demand. Based on the zone substation weather-corrected actual maximum demands and anticipated localised growth, a base (expected) growth 10% PoE maximum demand forecast for each individual zone substation is developed. These zone substation forecasts are then aggregated to the corresponding terminal station based on relevant diversity factors while adjusting for sub-transmission losses. This provides the bottom-up non-coincident terminal station demand forecasts which are then reconciled with the top-down forecasts.

NIEIR prepares a top-down maximum demand forecast for the UE service area using econometric energy models. NIEIR has developed a method for modelling and forecasting summer and winter maximum demand using its proprietary PeakSim model. This model generates probability distributions of maximum demand from synthetically generated distributions of temperature. High, base (expected) and low economic growth forecasts are developed for maximum demand at 10%, 50% and 90% PoE summer temperature levels and 10% PoE and 50% PoE winter temperature levels for UE at each terminal station as well as the total coincident UE network demand. NIEIR uses its regional economic projection models for the UE service area to develop its forecasts. Information that NIEIR considers includes:

o Economic outlook and population growth for Victoria and UE supply area.

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o Government policies which impact on electricity demand and consumption.

o The impacts of air-conditioning usage, retail electricity prices, electric vehicles, energy efficiency and micro-generators.

o Variation in temperature patterns.

In 2012 UE engaged AECOM to develop a top-down UE service area maximum demand forecasting model to be used internally by UE for validation of the NIEIR model results. This model uses the eViews software, which operates in a similar but more simplified manner to NIEIR’s PeakSim model. The model uses a combination of regression and Monte-Carlo simulation to develop the forecasts.

The process that UE takes to reconcile the three maximum demand forecasts is as follows:

1. The top-down non-coincident maximum demand forecasts for terminal stations prepared by NIEIR is compared against the bottom-up non-coincident maximum demand terminal station forecasts prepared by UE.

2. The top-down coincident maximum demand forecasts for the UE service area prepared by NIEIR is compared against the aggregated and diversified bottom-up maximum demand forecasts prepared by UE.

3. The top-down coincident maximum demand forecasts for the UE service area prepared by NIEIR is compared against the top-down coincident macro-economic maximum demand forecasts developed by UE using the AECOM eViews model.

Any material discrepancies are investigated, with the appropriate forecast adjusted if necessary to ensure consistency and accuracy. Otherwise if the discrepancy is small, all bottom-up forecasts developed by UE are scaled to match the top-down NIEIR maximum demand forecasts for the UE service area with post-model adjustments for disruptive technologies applied.

Once reconciled, UE uses the bottom-up forecast for the purpose of planning the network, as this provides detailed information at the asset (spatial) levels to identify emerging capacity limitations.

5.2 Forecasting assumptions

5.2.1 Actual maximum demand calculations

The actual maximum demand, and the date and time of the maximum demand for the previous summer are collected from historical metering databases.

The actual maximum demands are calculated assuming gross metered embedded generation are out-of-service in the absence of a formalised network support agreement. Household solar photovoltaic panels are installed on UE’s network using net-metering, hence they are captured in UE’s maximum demands as negative load.

UE adjusts the asset level actual maximum demands to a system-normal configuration if abnormalities are observed. Load transfers during outage conditions are accounted for by subtracting demand from one feeder and adding the same demand to another. Load shedding is accounted for in the asset level maximum demands by adding on the demand that was shed.

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5.2.2 Weather-correction

The variability in the weather can have significant impacts on the actual recorded maximum demands year on year. To assess the underlying growth trend, the actual maximum demands are normalised against defined average ambient temperature conditions each with a particular probability of exceedance (PoE). This process is known as weather-correction and is applied to actual maximum demands to estimate what the demand would have been under a particular temperature condition. This allows a direct comparison to be made between forecasts and actuals by normalising the impact of hot weather.

When the actual PoE for the given summer maximum demand day is lower than the target PoE for weather-correction, then that year’s data is used for applying the weather correction. When the actual PoE for the given summer is greater, UE uses the historical base year trace from 2008-09 to fill the gap at higher ambient temperatures for determining the rate of change of demand with high ambient temperatures for weather correction purposes. The 2008-09 year is the most recent year representing a less than 10% PoE demand profile during a non-holiday period.

Based on the historical demand profiles in the UE network, a clear difference is identified in the demand behaviour in the Mornington Peninsula compared with the rest of the UE distribution network. Given the Mornington Peninsula is a holiday destination, maximum demands of zone substations in the Mornington Peninsula generally occur during the Christmas holiday period or a weekend during the summer school holiday period. Therefore, the Mornington Peninsula and the rest of the network are assessed independently in the weather-correction process.

5.2.2.1 Excluded days

Certain days are excluded from the weather-correction assessment as they affect the temperature sensitivity calculations.

For the Mornington Peninsula, all the public holidays and weekends are included into the weather-correction calculation as these are also likely to be high demand days. Only the days having network abnormalities (i.e. load transfers, outages) are excluded.

The following days are excluded from the weather-correction calculations for the rest of the network:

o Public holidays:

Australian Day

Labour Day

Melbourne Cup day

Christmas period (from 15 December to 15 January)

o Weekends

o Any other days with network abnormality

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5.2.2.2 Reference temperatures

NIEIR has defined the 10%, 50% and 90% PoE average daily temperatures for the UE service area forecasts based on 50-years of historical data at the Bureau of Meteorology (BOM) Melbourne Regional Office and Melbourne Olympic Park weather stations for 2016-17, as shown below.

Table 10 – Average daily temperature at Melbourne Olympic Park weather station

Probability of Exceedance (POE)

Average daily temperature (°C) 20

Summer

10% 34.5

50% 31.5

90% 29.3

These temperatures can change due to the effects of urban warming raising overnight minimum temperatures. Based on the above, if the average Melbourne daily temperature on a day reaches 34.5ºC, then the weather condition would lead to a maximum demand that would be considered to be a 1 in 10 year event (generally referred to as 10 th percentile probability of exceedance, or 10% PoE). The forecast maximum demand associated with this particular temperature condition is referred to as a 10% PoE forecast maximum demand.

In order to represent the ambient temperature profile of particular assets within the UE network, temperature readings at two BOM weather stations are used.

1. Mornington Peninsula – Cerberus weather station.

2. Rest of the network – Scoresby weather station.

The 10% PoE temperature thresholds at Cerberus and Scoresby weather stations were calculated as shown below for the 2016-17 summer.

Table 11 – 10% PoE average temperatures at Cerberus and Scoresby weather station

Location 10% PoE Average daily

temperature (°C)

Cerberus 31.8

Scoresby 33.8

The average daily temperatures presented above are used to develop the weather-corrected 10% PoE maximum demand forecasts for each zone substation.

20 Average of the peak day temperature and the previous night’s minimum temperature.

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5.2.3 New and retiring developments

UE maintains a register which captures large customer connections and connection enquiries within the UE service area. Some of the loads identified may not materialise or customers may only use part of the initial estimate of their maximum demand. Given this uncertainty, only a portion of the load recorded in the register is used in the forecasting process as explained below:

1. Given the total requested load is typically not materialised at once when the service is connected, UE assumes that only a portion of the load materialises in the year of the connection with the balance materialising the following year.

2. In most cases, the total installed capacity or the requested ultimate demand will not be utilised. As a result, UE adopts different utilisation factors across all customer classifications (commercial, industrial, residential or combination) unless there is a high level of confidence that the customer would take a greater portion of the capacity.

3. The maximum demand of the individual new load and the zone substation peak may not perfectly coincide. In order to accommodate this, UE adopts a diversity factor in calculating maximum demand.

Adjusting for these factors, the new large loads captured in the register are allocated to individual zone substations. If the demand contribution and timing are certain for large projects (i.e. data centres, shopping complexes, multilevel high density residential development), actual information is used in the forecasting process. Large customer disconnections or known reductions in demand are also captured at this point in the process.

5.3 Maximum demand forecast accuracy

Although current maximum demand forecasts show a slower growth rate than has previously been experienced over the last ten years, 10% PoE electricity maximum demand in UE’s service area is projected to continue to grow at 1.1 percent per annum over the next ten years.

In practise, each network asset needs to be planned to support the localised demand within the relevant subsection of the UE service area for which it supports, and be operated within its rating. As UE’s service area is not homogenous, there are some assets experiencing higher than average maximum demand growth and some that are experiencing lower than average maximum demand growth. Furthermore, there are some assets in the UE fleet that are currently operating well above the average utilisation and some operating well below. Under our probabilistic planning process, demand-related capital expenditure is only directed to those parts of the network where it is economic to do, predominantly in those areas where assets are operating well above the average utilisation and where the maximum demand growth rate is higher than the average.

To assess the accuracy of UE’s forecasting, a weather-corrected actual demand is calculated based on the observed PoE temperature conditions of the previous summer. This is then compared against the forecast for the summer undertaken in the previous year. The results of the weather-corrected actual and the historical (and current) forecast based on a 50% PoE are overlaid in the figure below.

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Figure 12 – UE summer maximum demand (MW)

Since 2006, the difference between the forecast and the weather-corrected actual maximum demand has remained within the extremes of -3.29% and +3.16% with an average error over the period of -0.54%.

1400

1500

1600

1700

1800

1900

2000

2100

2200

2006 2008 2010 2012 2014 2016 2018 2020

Maxim

um

Dem

an

d (

MW

)

YearForecast 50% PoE MD Weather-corrected 50% PoE Actual MD Actual MD

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6 Network development plan

6.1 Network development planning process

Reliable and secure electricity supply is vital to the Australian national economy and social framework. This importance extends to the local economy and communities contained within UE’s service area. UE’s network development planning process creates value for UE’s customers by maintaining long-term supply reliability through prudent investment in the network and optimisation of the network configuration to manage overload risk caused by electricity demand growth. At the same time, UE minimises the whole-of-lifecycle capital and operating costs of any investment by ensuring that developments are economic and optimal from a solution and timing perspective. This planning is done within the regulatory framework of the National Electricity Rules (NER) and the Victorian Electricity Distribution Code.

UE’s network development and planning involves the process of selecting and determining the optimum timing of technically acceptable projects, whether they be network or non-network based solutions, using robust maximum demand forecasts to facilitate customer maximum demand being met with all electrical plant in service for all but one in ten years. It also involves management of the level of operational risk for the event of a credible critical contingency, taking into account the probability of power system equipment failure by applying probabilistic planning techniques and developing contingency plans.

Network development planning forms an integral part of asset management. A structured, coordinated network development planning process is essential to ensure solutions to current problems are optimal to meet both current and future requirements. To ensure that the objectives of network development planning are achieved, it is essential that it is undertaken in a structured, transparent and rigorous manner and makes best use of all relevant information available. The key objectives of UE’s network planning are to:

Meet customer driven growth through the identification of network limitations including thermal constraints, fault level limits, voltage and quality of supply compliance, asset replacement or refurbishment needs and new connections.

Maintain reliability and security of supply levels.

Ensure compliance with regulatory requirements.

Implement economically optimal solutions.

To deliver the network development objectives, UE has established a structured network development planning process. The diagram below is a flow chart illustrating the process used by UE to identify network limitations, quantify the amount of load-at-risk and to investigate options to relieve limitations including identification of the preferred solution (or jointly with other distribution businesses for shared assets).

This process also engages proponents of non-network solutions to find opportunities to defer network augmentation.

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Figure 13 – UE distribution network development planning process

Process after publishing DAPRProcess before publishing DAPR

Network historical load records

Load Forecasting(Medium to Long term)

Calculate plant ratings based on pre-defined

standard conditions and load profiles

Undertake network risk assessment

Is the annualised value of expected

unserved energy greater than annualised cost of

augmentation?

Prepare contingency plans

Implement contingency measures

Propose network augmentations

Determine optimum timing

Publish Distribution Annual Planning Report

Hold public forum to discuss non-network opportunites

Invite non-network service providers to provide alternatives to network augmentation

Undertake detailed economic and technical assessment to identify the preferred option(s)

(joint planning if applicable)

Undertake RIT-D assessment(if applicable)

Plan and implement preferred option(s)

Do non-network options address

network limitations?

No

Develop Non-Network Project Offer

Notify AEMO as required and provide access

standards

Approve business case

Execute Network Support Agreement

Approve business case

Develop internal business case

Is the network limitation on the shared

distribution system?

Identify potential network options

(including preferred network option)

Identify potential options though joint planning with UE and other Victorian DNSPs

(including preferred network option)

No Yes

Identify the lead DNSP to develop project(if applicable)

Yes

Satisfy RIT-D requirements (if applicable)

NoYes

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6.2 Planning standards

6.2.1 Reliability and security of supply standards

Planning criteria and network design standards influence the level of capital expenditure for accommodating growth in customer demand, and the underlying security of supply. The planning approach adopted by UE is probabilistic, taking into account the combination of load profiles, network topology, plant ratings and plant unavailability to quantify the exposure of customers to loss of supply. This approach allows an economic balance to be made between the cost of network reinforcement and the probability-weighted cost of loss of supply to customers.

UE’s electricity distribution network is augmented based on a probabilistic planning approach where the cost of power supply interruption to customers is assessed against the annualised cost of a network augmentation. When the annualised cost of power supply interruptions to customers exceeds the annualised cost of augmentation, the augmentation becomes economically viable. This approach means that plant is loaded above its cyclic (N-1) rating before an augmentation can become economic.

To adequately identify and to minimise the impact of load shedding events in circumstances where the (N) rating is exceeded, UE plans on a one-in-ten year weather temperature probability (i.e. 10% PoE), using a base (expected) economic growth maximum demand forecast to facilitate identifying economic circumstances where maximum demand can be supplied with all plant in-service for all but one-in-ten years. The probabilistic planning approach is then applied to cater for a single contingency using a suitable combination of 10%, 50% and 90% PoE maximum demand forecasts and plant failure details. This ensures that an economic balance is struck between the cost of augmentation and some exposure to possible loss of supply when the thermal capability of the network is exceeded either with all plant in service or in the event of an asset forced outage.

In order to determine the economically optimum level of investment, it is necessary to place a value on supply reliability from the customers’ perspective. It is recognised that this value may depend on the customers involved (and the duration of the outage). Estimating such a value is inherently difficult. It is common practice by many utilities in the world to use an average marginal value of reliability, referred to as the Value of Customer Reliability (VCR). The VCR used by UE is based on the values provided by AEMO. It is an updated estimate of the composite (or average) value of customer reliability in Victoria for all electricity customers. VCR is an important signal for investment and determining reliability levels. In establishing a case for an augmentation project, location specific VCR values may be used to reflect the different classes of customers served by the augmented facility. To satisfy the requirements of RIT-D, a set of scenarios is applied to test the sensitivity of the economic viability of proposed augmentation against credible variations in VCR.

A major consequence of the probabilistic planning approach adopted by UE is a reduced level of network redundancy and system security at times of high demand when assets are highly utilised. To ensure reliability performance of the network is not compromised, in developing and augmenting the network, UE aims to maintain risks associated with network capacity at manageable levels. UE achieves this by undertaking detailed contingency planning prior to the summer season of high demand. The purpose of the contingency planning is to reduce the impact of unplanned outages should they occur at times of maximum demand. In a network planned in accordance with the probabilistic approach, there are conditions under which the entire load cannot be supplied with a network element out-of-service. Contingency plans are therefore developed to restore supply for such events as reasonably quickly as possible. As demand and network utilisation increases over time, the efficacy of contingency plans in terms of managing

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network risks reduces, at some point triggering further capacity augmentation. Contingency planning is an important tool for network risk management. UE’s contingency planning covers:

Pre-contingent network optimisation prior to the high demand season to ensure plant is operating within thermal capability under system-normal conditions;

Remote selective load shedding and emergency load reduction capability from the control centre;

Assigning short-term ratings (24-hour, 2-hour and 10-minute) for critical plant items;

Inter-station remote controlled switches on distribution feeders to enable fast load transfers (within 10 minutes) from the UE Network Control Centre;

Assessment of transfer capability away from the highly utilised plant and preparation of detailed switching instructions for execution following a contingency;

Communication plan for sensitive customers to keep them up-to-date with emerging network limitations on days of high demand;

Operational measures including stepping up of field resource level and stock of spare equipment during the high demand period;

Demand management and network support programmes;

Deployment of relocatable transformers in the event of an emergency21; and

Emergency sub-transmission tie-lines to cover transmission connection asset failure.

Overall, probabilistic planning has consistently delivered more cost-effective network performance outcomes for UE customers and this has contributed to UE delivering lower-cost network charges to its customers relative to other distribution businesses around Australia. UE, by industry benchmarks, has a very highly utilised, optimised network. The probabilistic network planning approach informed by the VCR and backed up by appropriate contingency plans, is expected to deliver a level of supply security and reliability at an acceptable level of cost to the community.

6.2.2 Energy loss reduction standards

In every major network augmentation project, UE evaluates the energy loss reduction that could be achieved from each feasible option, including network and non-network solutions. Network energy loss reduction benefits are valued based on the average cost of electricity generated in Victoria (the market weighted average spot price).

Energy losses are therefore valued on the current cost of energy in such a way as to minimise the overall cost of electricity for consumers. This methodology is in accordance with regulatory requirements and current industry practice.

21 UE owns one 20/33 MVA 66/11 kV and one 12/20 MVA 66/22 kV relocatable transformer which are currently in-service at two UE zone substations under normal operating conditions. Under emergency conditions, these transformers could be deployed to another zone substation within 5-7 days.

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The standards set for network design have long term consequences given the expected life of most electrical infrastructure. On this basis there is good reason to consider the future cost of energy when designing the network to minimise both present and future capital and operating costs. Importantly, decisions made now to improve efficiency will have benefits based on future energy costs, which are expected to increase as cleaner forms of electricity generation are adopted.

UE therefore uses standard conductor sizes for new and augmented sub-transmission and distribution power lines which optimise the thermal current-carrying capacity reduce electrical losses and meet economic criteria by minimising the overall cost to customer of the distribution of electrical energy. Similarly, power transformers and other electrical plants are also specified to provide adequate power capability, whilst also minimising electrical losses and overall costs to customers in accordance with industry standards.

6.3 Key assumptions that drive timing of augmentation

6.3.1 Forecast summer maximum demand growth

Although recent demand forecasts22 have shown a slower growth rate than has previously been experienced, electricity demand in UE’s service area is projected to continue to grow. Growth in UE’s 10% PoE summer maximum demand is expected to be 1.1 percent per annum on average over the next ten years.

6.3.2 Value of Customer Reliability

In order to determine the economically optimal level of augmentation, it is necessary to place a value on supply reliability from the customers’ perspective. It is common practice by many utilities in the world to use an average marginal value of reliability, referred to as the Value of Customer Reliability (VCR).

For the DAPR, UE uses an updated estimate of the composite (or average) value of customer reliability in Victoria for all electricity customers. A location specific VCR is used by UE to reflect the different classes of customers served by the augmented facility when undertaking detailed analysis on emerging network limitations identified in this DAPR.

22 The revised maximum demand forecasts are aligned to and entirely consistent with the AER’s final determination on UE’s 2016-2020 Augmentation proposal.

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Table 12 – Value of customer reliability (nominal)

VCR ($/kWh) Summary of indexed VCR using OGW methodology23 and following 2014 VCR review

Year Residential Agricultural Commercial Industrial Victoria

2008 21.76 100.09 95.58 37.99 53.07

2009 23.45 139.60 101.77 40.45 56.91

2010 23.92 123.48 102.16 40.60 57.36

2011 24.16 134.94 105.50 41.93 58.83

2012 25.48 150.84 110.56 43.94 61.83

2013 27.19 147.76 113.05 44.93 63.09

2014 24.76 47.67 44.72 44.06 39.50

2016 25.42 48.94 45.91 45.23 40.55

Following a review of the national VCR, AEMO published the latest composite Victorian VCR on 30 September 2014 as shown in the table above. This review has resulted in a significant reduction in the VCR estimates for the commercial and agricultural sectors compared to the results of the 2007-08 VCR study (basis for the 2013 VCR estimates). This has led to a reduction in AEMO’s estimate of the composite VCR from $63,090 per MWh to $39,500 per MWh (a reduction of approximately 40%).

AEMO did not revise VCR in 2015 and does not intend to publish a latest VCR in 2016, therefore, UE has adopted AEMO’s 2014 VCR estimates, escalated by a factor of 1.013 using the 2015 CPI index, and weighted in accordance with the composition of the load, by sector, for all electricity customers in Victoria. The VCR of $40,550 per MWh is used to identify the upcoming network investments for this year’s DAPR.

6.3.3 Plant forced outage rates and durations

The VCR is only one component in quantifying cost of loss of supply to customers. It must also be combined with the expected unavailability of distribution network plants based on forced outage rates and outage durations. The base (average) reliability data adopted by UE is shown in the following tables. The data is derived from the Australian CIGRE Transformer Reliability Survey carried out in 1995 and UE’s observed network performance since 1994-95.

Table 13 – Sub-transmission line outage data

Major plant item: Sub-transmission lines Interpretation

Line failure rate (sustained fault)

5.1 faults per 100 km per annum The average sustained failure rate of UE’s sub-transmission lines is 5.1 faults per 100 km per year.

Duration of outage (sustained fault)

8 hours On average 8 hours is required to repair an overhead line however cable faults can take considerably longer.

Expected line unavailability per year

𝑅𝑒𝑝𝑎𝑖𝑟 𝑡𝑖𝑚𝑒

𝑅𝑒𝑝𝑎𝑖𝑟 𝑡𝑖𝑚𝑒 +(24 × 365)

(𝑓𝑎𝑖𝑙𝑢𝑟𝑒 𝑟𝑎𝑡𝑒 × 𝑙𝑒𝑛𝑔𝑡ℎ)

On average, a 10 km sub-transmission line is expected to be unavailable due to a fault for about 0.046% of the time, or 4 hours in a year.

23 Source: AEMO

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Table 14 – Zone substation transformer outage data

Major plant item: zone substation transformer Interpretation

Transformer failure rate (major fault)

0.5% per annum A major failure is expected to occur once per 200 transformer-years. Therefore, in a population of 100 zone substation transformers, for example, one major failure of any one transformer would be expected every two years.

Duration of outage (major fault)

2190 hours A total of 3 months is required to repair / replace the transformer, during which time the transformer is not available for service.

Expected transformer unavailability per year

𝑅𝑒𝑝𝑎𝑖𝑟 𝑡𝑖𝑚𝑒

𝑅𝑒𝑝𝑎𝑖𝑟 𝑡𝑖𝑚𝑒 +(24 × 365)

(𝑓𝑎𝑖𝑙𝑢𝑟𝑒 𝑟𝑎𝑡𝑒 )

On average, each transformer would be expected to be unavailable due to major failure for 0.125% of the time or 11 hours in a year.

It is important to note that once the transformer insulation condition crosses below a threshold value, the transformer is deemed to be near or at the end of the economic life, and is at an elevated risk of insulation failure caused by mechanical stresses that occur during a short-circuit fault. In such cases, a specific transformer outage rate is calculated based on the zone substation fault level, number of transformers per site, insulation condition and the annual number of faults.

6.3.4 Plant thermal ratings

Summer cyclic ratings based on ambient temperature of 40°C for zone substation transformers, sub-transmission circuits and distribution feeders are adopted in this document. In addition to temperature, overhead line ratings are based on solar radiation of 1000 W/m2 and a wind speed of 3 m/s at an angle to the conductor of 15° (i.e. an effective transverse wind speed of 0.78 m/s), while the underground cable ratings are based on soil thermal resistivity of 0.9 °Cm/W or 1.2 °Cm/W at specific sites.

6.3.5 Discount rates

A discount rate currently at 6.37% (real, pre-tax) has been adopted in undertaking the economic analysis, and calculating the annualised cost of augmentation. This discount rate represents a reasonable commercial discount rate, appropriate to the analysis of a private enterprise investment in the electricity sector.

6.3.6 Load transfer capability

In the event of a major plant failure, load could be transferred away from sub-transmission systems and zone substations using the distribution feeder networks to reduce the impact of an outage. UE has estimated the amount of load that could be transferred away from each sub-transmission system and zone substation for summer 2016-17. These transfers have not been considered in the direct estimation of the unserved energy. Whist the risk assessments presented in this DAPR adopt a simplistic approach in terms of considering load transfer capability, they will be a matter for detailed consideration in a RIT-D and/or UE’s internal business case prior to committing to a particular network augmentation.

6.4 Committed augmentation projects

UE plans to augment the distribution network and to transfer and optimise the balance of load between zone substations, sub-transmission systems and distribution feeders. The load-at-risk

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assessment considers the impact of projects that are already committed and shows how the maximum demand is expected to change compared with plant ratings. The committed projects considered in this document are presented in Table 15.

Table 15 – Committed augmentation projects

Project Expected commissioning date

(before summer)

Notting Hill (NO) third transformer 2017-18

Hasting (HGS) to Rosebud (RBD) 66kV sub-transmission line 2022-23

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6.5 Forecast distribution network limitations overview

Figure 14 to Figure 16 shows the present and emerging distribution network limitations (refer to Table 16), including RIT-D assessment that UE may conduct in the next 5 year planning period.

Figure 14 – Zone substation and sub-transmission system limitations (schematic view) showing limitation reference number

2

1

4

3

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Figure 15 – Distribution feeder limitations (in UE’s northern service territory) showing limitation reference number

10

6

5

7

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Figure 16 – Distribution feeder limitations (in UE’s southern service territory) showing limitation reference number

9

8

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Table 16 provides detailed information in relation to each identified distribution network limitations.

Table 16 – Description of the identified distribution network limitations showing limitation reference number

LIMITATION 1 – EAST BURWOOD SUPPLY AREA


If there is a forced outage of critical sections of the SVTS-EB-RD-SVTS sub-transmission during summer maximum demand periods, there will be insufficient capacity on this system to supply all demand from summer 2016-17.

This system is presently limited by the SVTS-EB 66 kV line, for an outage of the SVTS-RD 66 kV line.

Location The suburbs most likely to be affected include Burwood East and Forest Hill presently supplied by UE’s East Burwood (EB) zone substation


Description Re-conductor 0.75km of the SVTS-EB 66 kV line

Cost estimate $530,000





Type of solution In order to avoid supply interruptions to customers connected to EB zone substation, post-contingent non-network solutions are required



To defer the proposed augmentation by 12 months, a non-network solution would need to reduce the maximum demand at EB zone substation, between the hours of 15:00 to 20:00 on weekdays by approximately 4.0 MVA



Status UE welcomes interested parties to submit their proposals or engage in joint planning now to defer or avoid the proposed network augmentation


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If there is a forced outage of critical sections of the TSTS-DC-TSTS sub-transmission system during summer demand periods, there will be insufficient capacity on this system to supply all demand from summer 2016-17.



Description Up-rate TSTS-DC No.1 66kV line and droppers which is strung on towers owned by AusNet Transmission Group by 2017-18.









To defer the proposed augmentation by 12 months, a non-network solution would need to reduce the maximum demand at DC zone substation, between the hours of 14:00 to 20:00 on weekdays by approximately 1.0 to 2.0 MVA.


The estimated total annual cost of the preferred option is $12,740. This provides a broad upper bound indication of the maximum annual contribution from UE which may be available to non-network service providers for deferring or avoiding the need for proposed network augmentation.

Status Exempted from RIT-D assessment

However, UE welcomes interested parties to submit their proposals or engage in joint planning to defer or avoid the proposed network augmentation works


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If there is a forced transformer outage at Doncaster (DC) zone substation during summer maximum demand periods, there will be insufficient capacity at DC zone substation to supply all demand from summer 2016-17. As a consequence, some customers supplied from DC zone substation are exposed to risk of supply interruption.


A number of distribution feeders within the DC supply area are highly utilised. This can limit transfer capability between feeders during emergency conditions. As a consequence, some customers are exposed to risk of supply interruption.

A number of distribution feeders have shown poor reliability performance compared to the overall UE network. More specifically, DC 1, DC 3, DC 4, DC 5, DC 6 and DC 12 are amongst UE’s top 50 worst performing feeders.



Description Install a fourth 20/33 MVA 66/22 kV transformer at DC zone substation together with two new high-voltage distribution feeders.

An alternative option being considered is the establishment of a new single transformer zone substation in Templestowe.

Cost estimate $8 million








To defer the proposed augmentation by 12 months, a non-network solution would need to reduce the maximum demand at DC zone substation, between the hours of 15:00 to 20:00 on weekdays by approximately 3.0 MVA



Status Identified for RIT-D assessment within the next 12 months

UE welcomes interested parties to submit their proposals or engage in joint planning to defer or avoid the proposed network augmentation


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LIMITATION 4 – EAST MALVERN SUPPLY AREA


If there is a forced transformer outage at East Malvern (EM) zone substation during summer maximum demand periods, there will be insufficient capacity at EM zone substation to supply all demand from summer 2016-17. As a consequence, some customers supplied from EM zone substation are exposed to risk of supply interruption


A number of distribution feeders within the EM supply area are highly utilised. This can limit transfer capability between feeders during emergency conditions. As a consequence, some customers are exposed to risk of supply interruption

Location The suburbs most likely to be affected include Alamein, Carnegie, Chadstone and East Malvern


Description Install a third 20/33 MVA 66/22 kV transformer at EM zone substation





The main contribution to the summer maximum demand comes from the commercial, residential and light-industrial sectors. Opportunities for demand reduction therefore exist in the commercial, residential and light-industrial voluntary load reduction schemes.

Type of solution In order to avoid supply interruptions to customers connected at EM zone substation, post-contingent non-network solutions are required.



To defer the proposed augmentation by 12 months, a non-network solution would need to reduce the maximum demand at EM zone substation, between the hours of 15:00 to 20:00 on weekdays by approximately 3.0 MVA.


The estimated total annual cost of the preferred option is around $446,000. This provides a broad upper bound indication of the maximum annual contribution from UE which may be available to non-network service providers for deferring or avoiding the need for proposed network augmentation.

Status Identified for RIT-D assessment beyond next 12 months.

UE welcomes interested parties to engage in joint planning to defer or avoid the proposed network augmentation


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LIMITATION 5 – WELLS RD, CHELSEA / CHELSEA HEIGHTS / ASPENDALE GARDENS / BANGHOLME AREA


CRM 35 feeder is a highly utilised feeder.

Location The suburbs most likely to be affected include some parts of Chelsea, Aspendale Gardens, Chelsea Heights, Edithvale and Bangholme electricity supply areas


Description Extend CRM 24 feeder to offload CRM 35

Cost $400,000







To defer the proposed augmentation by 12 months, a non-network solution would need to reduce the maximum demand on CRM 35, between the hours of 14:00 to 20:00 by approximately 0.5 MVA before summer 2018-19





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LIMITATION 6 – DANDENONG FRANKSTON RD, CARRUM DOWNS / DANDENONG SOUTH / SANDHURST AREA


DVY 24 feeder is a highly utilised feeder. The maximum demand on DVY 24 feeder is expected to exceed its summer cyclic rating from 2018-19.

Location The suburbs most likely to be affected include portion of Dandenong South, Carrum Downs and Sandhurst electricity supply areas


Description Build a new feeder DVY 12 to offload DVY 24

Cost $900,000







To defer the proposed augmentation by 12 months, a non-network solution would need to reduce the maximum demand on DVY 24, between the hours of 13:00 to 19:00 by approximately 2.0 MVA before summer 2018-19





LIMITATION 7 – GLENHUNTLY RD, ELSTERNWICK AREA


The maximum demand on EL 10 feeder is expected to exceed its summer cyclic rating from 2018-19.

Location This feeder supplies electricity along Glen Huntly Rd in the Elsternwick area


Description Build new EW feeder to offload EL 10

Cost $1.2 million




The main contribution to the summer maximum demand comes from the commercial sector on hot summer days. Opportunities for demand reduction therefore exist in the commercial voluntary load reduction schemes



To defer the proposed augmentation by 12 months, a non-network solution would need to reduce the maximum demand on EL 10 between the hours of 14:00 to 19:00 by approximately 4.0 MVA before summer 2018-19





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LIMITATION 8 – MT ELIZA WAY, MOUNT ELIZA / FRANKSTON FLINDERS RD, FRANKSTON SOUTH AREA


FSH 33 feeder is a highly utilised feeder during hot summer periods

Location The suburbs most likely to be affected include Mt Eliza and Frankston South

Preferred

network

solution

Description Build new feeder at FSH to offload FSH 33

Cost $330,000







To defer the proposed augmentation by 12 months, a non-network solution would need to reduce the maximum demand on FSH 33, between the hours of 16:00 to 20:00 by approximately 0.5 MVA before summer 2018-19





LIMITATION 9 – HALL RD, CARRUM DOWNS / SEAFORD / SKYE AREA


FTN 23 feeder is a highly utilised feeder

Location The suburbs most likely to be affected include Carrum Downs, Seaford and Skye

Preferred

network

solution

Description Permanent load transfer from FTN 23 feeder onto adjacent lightly loaded FTN 25 feeder

Cost $26,000







To defer the proposed augmentation by 12 months, a non-network solution would need to reduce the maximum demand on FTN 23, between the hours of 16:00 to 21:00 by approximately 0.5 MVA before summer 2017-18





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LIMITATION 10 – JELLS RD / FERNTREE GULLY RD, WHEELERS HILL AREA


The maximum demand on MGE 12 feeder is expected to exceed its summer cyclic rating from 2017-18.

Location The suburbs most likely to be affected include Scoresby and Wheelers Hill.


Description Establish new 22 kV feeder from MGE zone substation

Cost $1.4 million




The main contribution to the summer maximum demand comes from the commercial sector. Opportunities for demand reduction therefore exist in the commercial voluntary load reduction schemes.



To defer the proposed augmentation by 12 months, a non-network solution would need to reduce the maximum demand on MGE 12, between the hours of 11:00 to 18:00 by approximately 3.7 MVA before summer 2018-19.


The estimated total annual cost of the preferred option is $89,200. This provides a broad upper bound indication of the maximum contribution from UE which may be available to non-network service providers for deferring or avoiding the need for proposed network augmentation.

Status UE welcomes interested parties to submit their proposals to defer or avoid the network augmentation.


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6.6 Summary of Regulatory Investment Test for Distribution undertaken

UE is required to undertake Regulatory Investment for Distribution (RIT-D) in accordance with clause 5.17 of the National Electricity Rules (NER). This requires UE to engage in formal consultation with registered participants and interested parties where the cost of the most expensive credible option is more than $5 million.

As previously described, UE follows the three-stage RIT-D process set out in the NER:

Stage 1: Publish the Non Network Options Report (NNOR) which informs registered participants and interested parties of the identified need that UE wishes to alleviate. This report also includes the potential credible network solutions and the technical characteristics that a non-network solution would need to deliver to address the identified need. The purpose of this report is to identify alternative solutions.

Stage 2: Publish the Draft Project Assessment Report (DPAR) which presents the results of the cost-benefit assessment including the proposed preferred option to address the identified need. The purpose of this report is to provide a basis for consultation on the proposed preferred option.

Stage 3: Publish the Final Project Assessment Report (FPAR) which identifies the preferred solution. This is followed by the procurement process.

6.6.1 Current Regulatory Investment Test for Distribution

The table below provides an overview of the RIT-D assessments that are underway or completed by UE in 2016.

Table 17 – Status of UE Regulatory Investment Test for Distribution

Project name RIT-D status

Preferred option Expected commissioning date

(before summer)

Comments

Lower Mornington Peninsula Supply Area RIT-D

Completed

Implementing a 4-year demand management proposal and 2-year deferral of the new Hastings to Rosebud 66 kV line

Four year non-network solution to start from November 2018; and

Network augmentation to be implemented before December 2022

NNOR published in November 2014.

DPAR published in November 2015.

FPAR published in May 2016.

Notting Hill Supply Area RIT-D

Completed Installing third transformer at Notting Hill zone substation and two new distribution feeders

Network augmentation (preferred solution) to be implemented before December 2017

NNOR published in April 2016.

DPAR published in October 2016.

FPAR published in December 2016.

All RIT-D consultation reports, including submissions received during the consultation period are available from UE’s website.24

24 UE: Available at https://www.unitedenergy.com.au/industry/mdocuments-library/


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The RIT-D project is further described below.

6.6.1.1 Lower Mornington Peninsula Supply Area RIT-D

The purpose of the RIT-D was to address the following network limitations:

From summer 2016-17, an unplanned outage of the MTN-DMA 66 kV line during summer maximum demand conditions is expected to lead to voltage collapse in the lower Mornington Peninsula. This could lead to supply interruption to approximately 50,000 customers.

From summer 2016-17, an unplanned outage of a critical sub-transmission line during summer maximum demand condition is expected to lead to supply interruptions in the lower Mornington Peninsula due to thermal overload of remaining in-service sub-transmission lines.

UE published the NNOR in November 2014. In response to this report, UE received two submissions from non-network service providers. Both parties submitted a viable non-network solution proposal to defer the network solution by at least one year.

The table below sets out the credible options considered in this RIT-D assessment. It also summarises the Net Present Value (NPV) analysis of each option.

Table 18 – Credible options considered in this RIT-D assessment

Option Description

PV of estimated total cost

($,million)25

PV of Gross Market Benefits

($,million)26

NPV of Net Economic Benefit

($,million)27

Ranking under RIT-D

1 Installing approximately 53 km of new 66 kV line from Hastings (HGS) zone substation to Rosebud (RBD) zone substation by 2020-21.

22.90 54.77 31.87 2

2 Implementing GreenSync’s four year Demand Management solution starting from November 2018.

Installing approximately 53 km of new 66 kV line from Hastings (HGS) zone substation to Rosebud (RBD) zone substation before December 2022.

23.07 55.21 32.14 1

3 Implementing Aggreko’s five year Embedded generation solution at RBD zone substation from 2020 to 2024.

Installing approximately 53 km of new 66 kV line from Hastings (HGS) zone substation to Rosebud (RBD) zone substation by 2024-25.

24.52 54.33 29.81 3

The preferred option (Option 2 in Table 18 above) is to implement GreenSync’s 4-year demand management proposal by summer 2018-19 and establish a 53 km new 66 kV line from Hastings (HGS) to Rosebud (RBD) zone substation before December 2022. The total project cost, inclusive of operating costs, is estimated at $23.07 million (in present value terms).

25 Includes capital and operating costs. 26 The Gross Market Benefits under the base case scenario. 27 The Net Market Benefits under the base case scenario.

Strategy



The FPAR was published in May 2016 declaring Option 2 as the preferred solution.. UE has since signed a network support agreement with GreenSync Pty Ltd. The RIT-D project has no material impacts on the connection and distribution use of system charges for the Network Users.

6.6.1.2 Notting Hill Supply Area RIT-D

The purpose of the RIT-D is to address the following network limitation:

From summer 2016-17, an unplanned outage of one NO zone substation 66/22kV transformer during summer maximum demand conditions is expected to lead to supply interruptions in the Notting Hill electricity supply area due to thermal overload of remaining in-service zone substation 66/22kV transformer.

UE published the NNOR in April 2016. In response to this report, UE received one submission from a non-network service provider - Energy Developments Ltd (EDL). This submission proposed a viable non-network solution to defer the network solution by at least one year.

The table below sets out the credible options considered in this RIT-D assessment. It also summarises the Net Present Value (NPV) analysis of each option.

Table 19 – Credible options considered in this RIT-D assessment

Option Description

PV of estimated total cost

($,million)28

PV of Gross Market Benefits

($,million)29

NPV of Net Economic Benefit

($,million)30

Ranking under RIT-D

1 Install a third 20/33MVA 66/22kV transformer, one 66 kV bus tie circuit breaker and a third 22 kV bus at Notting Hill zone substation with two new 22 kV distribution feeders commissioned by Summer 2017-18

4.99 13.90 8.91 1

2 Contract EDL to provide their non-network support services for Summer 2017-18, followed by Option 1 ready for service by Summer 2018-19.

5.04 13.71 8.67 3

3 Contract EDL to provide their non-network support services for a four year period starting Summer 2017-18 in conjunction with implementation of partial Option 1 (i.e. third 22 kV bus at NO zone substation with two new 22 kV distribution feeders). This would then be followed by the installation of third 20/33MVA 66/22kV transformer and one 66 kV bus tie circuit breaker (remaining Option 1) ready for service by Summer 2021-22.

4.83 13.64 8.81 2

The preferred option (Option 1 in Table 19 above) is to Install a third 20/33MVA 66/22kV transformer, one 66 kV bus tie circuit breaker and a third 22 kV bus at Notting Hill zone substation with two new 22 kV distribution feeders commissioned by December 2017. The total project cost, inclusive of operating costs, is estimated at $4.99 million (in present value terms).

28 Includes capital and operating costs. 29 The Gross Market Benefits under the base case scenario. 30 The Net Market Benefits under the base case scenario.

Strategy



The FPAR was published in December 2016 declaring Option 1 as the preferred solution. The RIT-D project has no material impacts on the connection and distribution use of system charges for the Network Users.

6.7 Summary of joint planning outcomes

UE has not commenced or undertaken any joint planning studies with other Victorian Distribution Businesses in the last 12 months.

6.8 Summary of projects to address urgent and unforeseen network issues

UE has not identified any augmentation investments classified as an urgent or unforeseen network issue as described in clause 5.17.3(a)1 that require immediate consideration within this planning period. All committed augmentations to be carried out within the forward planning have been identified through our annual planning review process.

6.9 Forecast distribution network limitations

This section provides an overview of the forecast distribution network limitations over the next five years. The assessment is not a detailed planning analysis, but a high level description and quantification of the expected balance between capacity and 10% PoE maximum demand forecast over the next five years to identify current and emerging capacity limitations. The following key data are presented in this section (where appropriate):

Summer (N) rating: capability of the zone substation / sub-transmission system / high-voltage distribution feeder during summer periods with all plants in-service.

Summer cyclic (N-1) rating: capability of the network with a single plant out-of-service, taking into account of the variability of the demand over time. This represents the lowest overall capacity.

Embedded generation installed capacity: total installed capacity of embedded generation units (greater than 1 MW) that are connected to a zone substation.

Forecast maximum demand: 10% PoE summer maximum demand forecast.

Power factor: the ratio of the active power to the apparent power at maximum demand conditions.

Number of hours where load is greater than 95 percent of maximum load: based on the historical trace used in the risk assessment, assesses the load duration curve and the total hours during the year that the load is greater than 95 percent of maximum demand.

Load transfer capacity: the available capacity within the network to transfer load to adjacent zone substations through the distribution feeder network at time of 10% PoE maximum demand for summer 2016-17.

Energy-at-risk: the amount of energy that would not be supplied under 10% PoE maximum demand conditions.

Strategy



Hours-at-risk: the number of hours that would not be supplied under 10% PoE maximum demand conditions.

Expected energy-at-risk: the portion of the energy-at-risk after taking into account plant unavailability due to probability of major outage of critical assets.

Expected value of unserved energy: the cost of the expected unserved energy, obtained by multiplying the energy-at-risk by the VCR.

Data presented in this document is used to identify the likely timing of network options that are economic or other actions. However, the precise timing of augmentations or any other non-network solutions aimed at alleviating emerging limitations will be a matter for more detailed consideration in a RIT-D and UE’s internal business case for approving network augmentation.

6.9.1 Zone substations

6.9.1.1 Box Hill zone substation

Box Hill (BH) zone substation consists of three 20/33 MVA 66/22 kV transformers and supplies the suburbs of Blackburn, Box Hill and part of the Box Hill Central precinct.

A third 20/33 MVA 66/22 kV transformer was installed at BH in January 2014. This is reflected in the figure below.

Magnitude, probability and impact of loss of load

BH is a summer-critical zone substation. The actual maximum demand at BH for summer 2015-16 was 46.0 MVA which occurred on 08 March 2016 at approximately 5:25 pm.

The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station’s summer (N) and (N-1) ratings.

Strategy



Figure 17 – Forecast maximum demand against station ratings for BH zone substation

The figure above shows that the maximum demand at BH zone substation is expected to remain well within its summer (N-1) rating over the next five years.

Therefore, on the basis of the current forecasts, no major demand related augmentation is planned at BH zone substation over the next five years.

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BH zone substation summary

BH zone substation

Summer (N) rating (MVA) 109

Summer (N-1) rating (MVA) 73

Embedded generation capacity (MVA) 0

BH zone substation 2016-17 2017-18 2018-19 2019-20 2020-21

10% PoE summer maximum demand (MVA) 48.1 48.3 48.2 48.1 48.1

Power factor 1.00 1.00 1.00 1.00 1.00

Number of hours where 95% of peak load is expected 27 28 27 27 27

Load transfer capability (MVA) 14.9

Energy-at-risk (MWh) 0.0 0.0 0.0 0.0 0.0

Hours at risk (hours) 0 0 0 0 0

Expected unserved energy (kWh) 0 0 0 0 0

Expected value of unserved energy ($) 0 0 0 0 0

Strategy



6.9.1.2 Beaumaris zone substation

Beaumaris (BR) zone substation consists of two 20/30 MVA 66/11 kV transformers and supplies the suburbs of Beaumaris and Black Rock.


BR is a summer-critical zone substation. The actual maximum demand at BR for summer 2015-16 was 25.7 MVA which occurred on 8 March 2016 at approximately 6:46 pm.


Figure 18 – Forecast maximum demand against station ratings for BR zone substation

The figure above shows that the maximum demand at BR zone substation is not expected to increase over the next five years and remains below its summer (N-1) rating.

Therefore, on the basis of the current forecasts, no major demand related augmentation is planned at BR zone substation over the next five years.

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BR zone substation summary

BR zone substation




BR zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.98 0.98 0.98 0.98 0.98







Strategy



6.9.1.3 Bentleigh zone substation

Bentleigh (BT) zone substation consists of two 20/30 MVA 66/11 kV transformers and supplies the suburbs of Bentleigh, Bentleigh East and McKinnon.


BT is a summer-critical zone substation. The actual maximum demand at BT for summer 2015-16 was 27.5 MVA which occurred on 13 January 2016 at approximately 5:36 pm.


Figure 19 – Forecast maximum demand against station ratings for BT zone substation

The figure above shows that the maximum demand at BT zone substation is expected to exceed its summer (N-1) rating from 2018-19.

The bar chart below depicts the expected unserved energy with one transformer out of service for the 10% PoE demand forecast and the hours per year that the 10% PoE demand is expected to exceed the station’s summer (N-1) rating. The line graph shows the expected value of unserved energy in each year, for the 10% PoE demand forecast.

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Figure 20 – Annual hours at risk, expected unserved energy and expected value of unserved energy

As shown above, if there is a forced transformer outage during summer maximum demand periods, there will be insufficient capacity at BT zone substation to supply all demand in 2018-19 for about 6 hours.

It is emphasised that the probability of a major outage of a transformer occurring during summer maximum demand periods is very low – about 0.5% per transformer per year with the expected unavailability per transformer per year is about 0.25%. When the energy-at-risk is weighted by this low probability, the expected unserved energy is estimated to be 3 kWh in 2018-19. If no action is taken, this figure is expected to rise to 9 kWh in 2020-21, with the expected value of unserved energy of around $400 (based on a VCR of $40,550 per MWh).

Presently, there are no 66 kV sub-transmission line circuit breakers at BT zone substation. Therefore, a forced outage of one of the sub-transmission line into BT zone substation would also lead to an outage of one of the BT zone substation transformers. However, the probability of such outage is low and the restoration time is expected to be shorter compared to a transformer outage. Therefore, the magnitude of expected unserved energy would be marginally higher than the values presented in the figure above.

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Strategy



Feasible options for alleviation of limitations

The following options are technically feasible and potentially economic to mitigate the risk of supply interruption and/or to alleviate the emerging limitation.

1. Maintain contingency plans to transfer load to adjacent zone substations.

Plans to transfer load to adjacent zone substations via the distribution feeder network are established. These plans are reviewed annually prior to the summer season. Transfer capability away from BT zone substation is assessed at 5.9 MVA for summer 2016-17.

2. Install a third transformer at BT zone substation.

Installation of a third 20/33 MVA 66/11 kV transformer would alleviate the capacity limitations at BT zone substation.

Preferred network option(s) for alleviation of limitations

The magnitude of expected unserved energy presented in the figure above is very small. Until a longer-term solution is implemented, UE proposes to maintain contingency plans to transfer load quickly to adjacent zone substation for an unplanned outage of a transformer at BT zone substation under critical loading conditions.

Therefore, on the basis of the current forecasts, no major demand related augmentation is planned at BT zone substation over the next five years.

Strategy



BT zone substation summary

BT zone substation




BT zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.99 0.99 0.99 0.99 0.99







Strategy



6.9.1.4 Bulleen zone substation

Bulleen (BU) zone substation consists of two 20/30 MVA 66/11 kV transformers and supplies the suburbs of Bullen and Templestowe Lower.

Due to age and deteriorating condition of the existing 11 kV switchboard (manufactured in the 1960s), UE plans to replace this switchboard with modern equivalent before summer 2020-21. As part of this project, the transformer cables would also be replaced. The timing of the asset replacement is subject to updated asset information, re-alignment of other network projects and / or re-prioritisation of options to mitigate the deteriorating condition of the switchboard. Presently, the station’s summer (N) and (N-1) ratings are limited by the transformer circuit breakers and transformer cables. Once replaced, the station’s summer ratings are expected to be adequate to meet the maximum demand at BU zone substation.


BU is a summer-critical zone substation. The actual maximum demand at BU for summer 2015-16 was 27.6 MVA which occurred on 19 December 2015 at approximately 5:57 pm.

The figure below depicts the historical actual maximum demands, 10% PoE maximum demand forecast together with the station’s summer (N) and (N-1) ratings.

Figure 21 – Forecast maximum demand against station ratings for BU zone substation

The figure above shows that the maximum demand at BU zone substation is expected to exceed its summer (N-1) rating from 2016-17.

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As shown above, if there is a forced transformer outage during summer maximum demand periods, there will be insufficient capacity at BU zone substation to supply all demand in 2016-17 for about 15 hours.

It is emphasised that the probability of a major outage of a transformer occurring during summer maximum demand periods is very low – about 0.5% per transformer per year with the expected unavailability per transformer per year is about 0.25%. When the energy-at-risk is weighted by this low probability, the expected unserved energy is estimated to be 22 kWh in 2016-17. If no action is taken, this figure is expected to reduce to 2 kWh in 2020-21, with the expected value of unserved energy of around $100 (based on a VCR of $40,550 per MWh).

Presently, there are no 66 kV sub-transmission line circuit breakers at BU zone substation. Therefore, a forced outage of one of the sub-transmission line into BU zone substation would also lead to an outage of one of the BU zone substation transformers. However, the probability of such outage is low and the restoration time is expected to be shorter compared to a transformer outage. Therefore, the magnitude of expected unserved energy would be marginally higher than the values presented in the figure above.

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Plans to transfer load to adjacent zone substation at West Doncaster (WD) via the distribution feeder network are established. These plans are reviewed annually prior to the summer season. Transfer capability away from BU zone substation is assessed at 6.0 MVA for summer 2016-17.

2. Install new transformation at an adjacent zone substation.

Installing a fourth 20/33 MVA 66/22 kV transformer at Doncaster (DC) zone substation together with new distribution feeders is expected to be commissioned by December 2019. Once commissioned, distribution feeder works could potentially be used to offload BU by converting the existing 11 kV assets to 22 kV.

3. Install a third transformer at BU zone substation.

Installation of a third 20/33 MVA 66/11 kV transformer would alleviate the capacity limitations at BU zone substation.

4. Replace the existing 11 kV switchboard with modern equivalent.

Replacing the 11 kV switchboard and transformer cables, with modern equivalent, due to age and deteriorating conditions would alleviate the capacity limitations at BU zone substation.

5. Establish a new zone substation.

There are presently no sites under consideration to be developed as a new 66/11 kV zone substation to offload BU. However, UE has been considering establishing a new 66/22 kV Templestowe (TSE) zone substation to alleviate limitations at Bulleen, Doncaster and West Doncaster zone substations. Once commissioned, some load could be transferred away from BU to TSE by converting the existing 11 kV assets to 22 kV.


UE plans to replace the aged 11 kV switchboard together with transformer cables with modern equivalent before summer 2021. Once replaced, the station’s summer ratings are expected to be adequate to meet the maximum demand at BU zone substation.

Until a longer-term solution is implemented, UE proposes to maintain contingency plans to transfer load quickly to adjacent zone substation for an unplanned outage of a transformer at BU zone substation under critical loading conditions.

Therefore, on the basis of the current forecasts, no major demand related augmentation is planned at BU zone substation over the next five years.

Strategy



BU zone substation summary

BU zone substation




BU zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.99 0.99 0.99 0.99 0.99







Strategy



6.9.1.5 Burwood zone substation

Burwood (BW) zone substation is fully developed with three 10/13 MVA 22/11 kV transformers. BW zone substation supplies the suburbs of Ashwood and Burwood.

Due to age and deteriorating condition of the BW transformers, UE replaced the previously existing 10 MVA Transformer No.1 and Transformer No.2 with new 10/13 MVA transformers. After this replacement, the station’s summer ratings are adequate to meet the maximum demand at BW zone substation over the next five years. This is reflected in the figure below.


BW is a summer-critical zone substation. The actual maximum demand at BW for summer 2015-16 was 22.2 MVA which occurred on 8 March 2016 at approximately 5:45 pm.


Figure 23 – Forecast maximum demand against station ratings for BW zone substation

The figure above shows that the following the replacement of the BW transformers, the maximum demand at BW zone substation is expected to remain within its summer (N-1) rating over the next five years.

Therefore, on the basis of the current forecasts, no major demand related augmentation is planned at BW zone substation over the next five years.

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BW zone substation summary

BW zone substation




BW zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 1.00 1.00 1.00 1.00 1.00







Strategy



6.9.1.6 Clarinda zone substation

Clarinda (CDA) zone substation consists of one permanent 20/33 MVA 66/22 kV transformer and a relocatable 12/20 MVA 66/22 kV transformer acting as a hot spare. CDA zone substation supplies the suburbs of Clarinda and Oakleigh South.

Prior to summer 2012-13, CDA zone substation was equipped with a single transformer and relied on distribution feeder transfers from adjacent zone substation to cater for an outage of the main transformer. In lieu of installing a second transformer at CDA, UE has relocated the 12/20 MVA relocatable transformer from Dandenong Valley (DVY) zone substation to CDA. A larger capacity 20/33 MVA transformer was subsequently installed at DVY. This is reflected in the graph below.


CDA is a summer-critical zone substation. The actual maximum demand at CDA for summer 2015-16 was 34.1 MVA which occurred on 13 January 2016 at approximately 5:25 pm.


Figure 24 – Forecast maximum demand against station ratings for CDA zone substation

The figure above shows that the actual maximum demand at CDA zone substation has been above its summer (N-1) rating since 2011-12. Given demand over the next five years, there would be significant amount of energy-at-risk should a forced transformer outage (the larger main transformer) occur during maximum demand periods.

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As shown above, if there is a forced transformer outage of the larger main transformer during summer maximum demand periods, there will be insufficient capacity at CDA zone substation to supply all demand in 2016-17 for about 69 hours.

It is emphasised that the probability of a major outage of a transformer occurring during summer maximum demand periods is very low – about 0.5% per transformer per year with the expected unavailability per transformer per year is about 0.25%. When the energy-at-risk is weighted by this low probability, the expected unserved energy is estimated to be 516 kWh in 2016-17. If no action is taken, this figure is expected to rise to 579 kWh in 2020-21, with the expected value of unserved energy of around $23,500 (based on a VCR of $40,550 per MWh).

The relocatable transformer at CDA may need to be used at another 66/22 kV high-risk zone substation should a major outage of a transformer occur during summer maximum demand periods. While CDA has manageable capacity to remove the relocatable transformer at any time over the next five years, it would leave CDA zone substation with a single transformer.

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Plans to transfer load to adjacent zone substations at Heatherton (HT), Springvale South, Springvale West and Notting Hill (NO) via the distribution feeder network are established. These plans are reviewed annually prior to the summer season. Transfer capability away from CDA zone substation is assessed at 19.0 MVA for summer 2016-17.

2. Install a second transformer at CDA zone substation.

Installation of a second (fixed) 20/33 MVA 66/22 kV transformer would alleviate the capacity limitations at CDA zone substation.


There are presently no sites under consideration to be developed as a new 66/22 kV zone substation to offload CDA.


The risk assessment shows that the expected value of unserved energy is insufficient to justify augmentation within the next five years. Until a longer-term solution is implemented, UE proposes to maintain contingency plans to transfer load quickly to adjacent zone substation for an unplanned outage of a transformer at CDA zone substation during critical loading conditions.

Therefore, on the basis of the current forecasts, no major demand related augmentation is planned

at CDA zone substation over the next five years.

Strategy



CDA zone substation summary

CDA zone substation




CDA zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.99 0.99 0.99 0.99 0.99






Expected value of unserved energy ($) 21,000 22,500 26,000 23,900 23,500

Strategy



6.9.1.7 Caulfield zone substation

Caulfield (CFD) zone substation is fully developed with two 20/33 MVA 66/11 kV transformers and supplies the suburbs of Caulfield, Malvern and Glenhuntly including the Monash University Caulfield Campus precinct.

CFD zone substation was commissioned in March 2008 to replace the former Caulfield (T) 22/11 kV zone substation. As part of this rebuild project, CFD was incorporated into the former MTS-EL-EM-MTS sub-transmission system to form the present MTS-CFD-EL-EM-MTS sub-transmission system.


CFD is a summer-critical zone substation. The actual maximum demand at CFD for summer 2015-16 was 41.5 MVA which occurred on 8 March 2016 at approximately 6:54 pm.


Figure 26 – Forecast maximum demand against station ratings for CFD zone substation

The figure above shows that the actual maximum demand at CFD zone substation has been above its summer (N-1) rating for 2012-13 and 2013-14. Given a steady demand growth expected over the next five years, there would be significant amount of energy-at-risk should a forced transformer outage occur during maximum demand periods.

The bar chart below depicts the expected unserved energy with one transformer out of service for the 10% PoE demand forecast and the hours per year that the 10% PoE demand is expected to

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exceed the station’s summer (N-1) rating. The line graph shows the expected value of unserved energy in each year, for the 10% PoE demand forecast.


As shown above, if there is a forced transformer outage during summer maximum demand periods, there will be insufficient capacity at CFD zone substation to supply all demand in 2016-17 for about 91 hours.

It is emphasised that the probability of a major outage of a transformer occurring during summer maximum demand periods is very low – about 0.5% per transformer per year with the expected unavailability per transformer per year is about 0.25%. When the energy-at-risk is weighted by this low probability, the expected unserved energy is estimated to be 1,286 kWh in 2016-17. If no action is taken, this figure is expected to rise to 4,039 kWh in 2020-21, with the expected value of unserved energy of around $163,800 (based on a VCR of $40,550 per MWh).




Plans to transfer load to adjacent zone substations at Bentleigh (BT), Gardiner (K), Elsternwick (EL) and East Malvern (EM) via the distribution feeder network are established. These plans are reviewed annually prior to the summer season. Transfer capability away from CFD zone substation is assessed at over 10.3 MVA for summer 2016-17.

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2. Install new transformation at an adjacent zone substation

Install a third 20/33 MVA 66/11 kV transformer at East Malvern (EM) or Ormond (OR) zone substation. Once commissioned, distribution feeder works could potentially be used to offload CFD.


There are presently no sites under consideration to be developed as a new 66/11 kV zone substation to offload CFD.


The risk assessment shows that the expected value of unserved energy is insufficient to justify augmentation within the next five years. Until a longer-term solution is implemented which probably involves the installation of a third transformer at EM, UE proposes to maintain contingency plans to transfer load quickly to adjacent zone substation for an unplanned outage of a transformer at CFD zone substation during critical loading conditions.

Therefore, on the basis of the current forecasts, no major demand related augmentation is planned at CFD zone substation over the next five years.

CFD zone substation summary

CFD zone substation




CFD zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 1.00 1.00 1.00 1.00 1.00



Energy-at-risk (MWh) 516.8 719.0 1,058.1 1,361.3 1,623.0


Expected unserved energy (kWh) 1,286 1,790 2,634 3,388 4,039


Strategy



6.9.1.8 Cheltenham zone substation

Cheltenham (CM) zone substation consists of two 20/27 MVA 66/11 kV transformers and supplies the suburbs of Cheltenham, Highett and the Southland precinct.

Due to age and deteriorating condition of the CM transformers, UE plans to replace the existing 20/27 MVA Transformer No.1 (manufactured in the 1960s) with modern equivalent transformer before summer 2025-26. The timing of these replacements is subject to updated asset information, re-alignment of other network projects and / or re-prioritisation of options to mitigate the deteriorating condition of the transformers.


CM is a summer-critical zone substation. The actual maximum demand at CM for summer 2015-16 was 25.0 MVA which occurred on 13 January 2016 at approximately 2:56 pm.


Figure 28 – Forecast maximum demand against station ratings for CM zone substation

The figure above shows that the maximum demand at CM zone substation is expected to remain within its summer (N-1) rating over the next five years.

Therefore, on the basis of the current forecasts, no major demand related augmentation is planned at CM zone substation over the next five years.

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CM zone substation summary

CM zone substation




CM zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 1.00 1.00 1.00 1.00 1.00







Strategy



6.9.1.9 Carrum zone substation

Carrum (CRM) zone substation is fully developed with three 20/33 MVA 66/22 kV transformers and supplies the areas of Bangholme, Carrum, Carrum Downs, Chelsea, Patterson Lakes, Skye and Sandhurst. Steady demand growth at CRM is expected to continue with the ongoing development of new residential and industrial estates.

In December 2009, the station was augmented with a third 20/33 MVA 66/22 kV transformer together with three new distribution feeders.

One embedded generation scheme over 1 MW is connected within the CRM supply area. This scheme is brought into service as and when required by the customer.

Due to age and deteriorating condition of the existing 22 kV switchboard (manufactured in the late 1960s), UE plans to replace this switchboard with modern equivalent before summer 2020-21. The timing of this replacement is subject to updated asset information, re-alignment of other network projects and / or re-prioritisation of options to mitigate the deteriorating condition of the transformers.


CRM is a summer-critical zone substation. The actual maximum demand at CRM for summer 2015-16 was 74.8 MVA which occurred on 8 March 2016 at approximately 6:53 pm.


Figure 29 – Forecast maximum demand against station ratings for CRM zone substation

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The figure above shows that the actual maximum demand at CRM zone substation has been above its summer (N-1) rating for 2012-13, 2013-14 and 2015-16. Given a steady demand growth over the next five years, there would be significant amount of energy-at-risk should a forced transformer outage occur during maximum demand periods.



As shown above, if there is a forced transformer outage during summer maximum demand periods, there will be insufficient capacity at CRM zone substation to supply all demand in 2016-17 for about 20 hours.




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Plans to transfer load to adjacent zone substations at Dandenong Valley (DVY), Frankston (FTN) and Mordialloc (MC) via the distribution feeder network are established. These plans are reviewed annually prior to the summer season. Transfer capability away from CRM zone substation is assessed at 17.2 MVA for summer 2016-17.


A possible option is to install a third 66/22 kV transformer at Frankston (FTN) zone substation. However, a second 66/22 kV transformer at Langwarrin (LWN) zone substation offered the best solution by providing limited load relief for CRM while providing LWN with an (N-1) rating which reduces load-at-risk all year round. A second 20/33 MVA 66/22 kV transformer was installed at LWN zone substation in September 2014. Therefore, distribution feeder works could potentially be used to offload CRM.

3. Install a fourth transformer at CRM zone substation.

Installation of a fourth 66/22 kV 20/33 MVA transformer would alleviate the capacity limitations at CRM zone substation. As part of this project, three new distribution feeders would need to be established to improve distribution feeder utilisation and supply reliability in the area. Establishing new distribution feeders at CRM is expected to be challenging and costly given its close proximity to the Mornington Peninsula Freeway, and its remoteness from the growing load centres. This option would result in high 22 kV fault levels which shall be addressed using fault level mitigation solutions.

The estimated cost of this augmentation is estimated at $30 million. The sub-transmission connection portion of works required to utilise the capacity of a new transformer is estimated at $20 million while the zone substation portion of the works is estimated at $10 million.


Establishing a new 66/22 kV Skye (SKE) zone substation with five new distribution feeders. Skye or Carrum Downs is identified as suitable locality for a new zone substation to offload CRM because it allows the distribution feeder lengths to be shortened, thereby improving distribution feeder utilisation and supply reliability in this area. Once commissioned, some load would be transferred away from CRM to SKE.

This new zone substation would be supplied via a new 66 kV sub-transmission line from CBTS, which is expected to offload the heavily loaded CBTS-CRM-FTN-FTS-LWN-CBTS system.

The estimated cost of this augmentation is $26 million. The sub-transmission connection portion of works is estimated at $12 million while the zone substation establishment portion of works is estimated at $14 million.

Strategy




A second 20/33 MVA 66/22 kV transformer was installed at LWN zone substation in September 2014. Therefore, distribution feeder works could potentially be used to offload CRM.

Based on the current maximum demand forecast, no major demand related augmentation is planned at CRM zone substation over the next five years. Until a longer-term solution is implemented, UE proposes to maintain contingency plans to transfer load quickly to adjacent zone substations for an unplanned outage of a transformer at CRM under critical loading conditions.

Strategy



CRM zone substation summary

CRM zone substation



Embedded generation capacity (MVA) 11.8

CRM zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 1.00 1.00 1.00 1.00 1.00







Strategy



6.9.1.10 Doncaster zone substation

Doncaster (DC) zone substation is fully developed with two 20/27 MVA 66/22 kV transformers and one 20/30 MVA 66/22 kV transformer and supplies the areas of Box Hill North, Doncaster, Doncaster East, Doncaster Hill and The Pines precincts, Templestowe and parts of the Box Hill central precinct.

Being designated Principal Activities Centres, the maximum demand in the Doncaster Hill and Box Hill areas is expected to continue to grow steadily over coming years.


DC is a summer-critical zone substation. The actual maximum demand at DC for summer 2015-16 was 79.3 MVA which occurred on 13 January 2015 at approximately 5:54 pm.


Figure 31 – Forecast maximum demand against station ratings for DC zone substation

The figure above shows that with the exception of 2011-12 and 2014-15, the actual maximum demand at DC zone substation has been above its summer (N-1) rating. Given a steady demand growth over the next five years, there would be significant amount of energy-at-risk should a forced transformer outage occur during maximum demand periods.


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As shown above, if there is a forced transformer outage during summer maximum demand periods, there will be insufficient capacity at DC zone substation to supply all demand in 2016-17 for about 71 hours.

It is emphasised that the probability of a major outage of a transformer occurring during summer maximum demand periods is very low – about 0.5% per transformer per year with the expected unavailability per transformer per year is about 0.37%. When the energy-at-risk is weighted by this low probability, the expected unserved energy is estimated to be 2,388 kWh in 2016-17. If no action is taken, this figure is expected to rise to 3,757 kWh in 2020-21, with the expected value of unserved energy of around $152,400 (based on a VCR of $40,550 per MWh).

Presently, there are no 66 kV sub-transmission line circuit breakers at DC zone substation. Therefore, a forced outage of one of the sub-transmission line into DC zone substation would also lead to an outage of one of the DC zone substation transformers. However, the probability of such outage is low and the restoration time is expected to be shorter compared to a transformer outage. Therefore, the magnitude of expected unserved energy would be marginally higher than the values presented in the figure above.



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Plans to transfer load to adjacent zone substations at Box Hill (BH) and Nunawading (NW) via the distribution feeder network are established. These plans are reviewed annually prior to the summer season. Transfer capability away from DC zone substation is assessed at 15.8 MVA for summer 2016-17.

2. Install a fourth transformer at DC zone substation.

Installation of a fourth 20/33 MVA 66/22 kV transformer at DC would alleviate the capacity limitation at DC zone substation. As part of this project, two new distribution feeders would also be established to improve the distribution feeder utilisation and supply reliability in the area, and to utilise the additional transformation capacity provided. This option would result in high 22 kV fault levels which shall be addressed by a 22 kV bus-split system with a suitable auto-close control scheme. Furthermore some noise mitigation measures would need to be implemented to keep noise levels within acceptable environmental limits.

The estimated cost of this augmentation is at least $8.0 million.


Establishing a new 66/22 kV Templestowe (TSE) zone substation with new distribution feeders is regarded as a long-term solution to supply the growing electricity demand in this area. Templestowe is identified as a suitable locality for a new zone substation to offload DC because it allows the distribution feeders to be shortened, thereby improving distribution feeder utilisation and supply reliability in this area as well as addressing capacity limitations. Accordingly, UE purchased a site in 2012 within the Templestowe area for this zone substation. This new zone substation would be supplied via a new 66 kV sub-transmission line from TSTS to connect into the existing BU-WD 66kV line. The estimated cost of this augmentation is $19 million.

The need for the new TSE zone substation is driven by high demand growth in the areas supplied by the Bulleen, Doncaster and West Doncaster zone substations as well as addressing distribution feeder limitations in these areas. In the last two years, maximum demand forecasts for this area have growth revised downwards compared to previous years. As a result, the installation of a 4th transformer at DC zone substation may be a more economical solution in the short term.


Based on the current maximum demand forecast, UE intends to install a fourth 20/33 MVA 66/22 kV transformer at DC zone substation together with two new distribution feeders before summer 2019-20.

The estimated cost of this augmentation is at least $8.0 million. In the absence of any lower-cost options, this is the most likely least cost technically feasible network option.

This augmentation shall:

Address capacity limitations at DC zone substation;

Strategy



Address the capacity limitations on the TSTS-DC-TSTS system;

Address the capacity limitations on the distribution feeders; and

Improve poor supply reliability in the area to a limited extent.

Until a longer-term solution is implemented, UE proposes to maintain contingency plans to transfer load quickly to adjacent zone substation for an unplanned outage of a transformer at DC zone substation under critical loading conditions.

Technical requirements of non-network solutions

Embedded generation or demand management schemes to reduce the magnitude of maximum demand within the areas presently supplied by DC zone substation could defer or avoid the proposed network augmentation.

The main contribution to the summer maximum demand comes from the commercial sector and the residential sector air-conditioning demand on hot summer days. Opportunities for demand reduction therefore exist in the commercial and residential voluntary load reduction schemes.

Figure 33 – DC zone substation load profile on maximum demand day (2013-14)

In order to defer the proposed augmentation by twelve months, a non-network solution would need to reduce the summer maximum demand at DC zone substation, between the hours of 15:00 to 20:00 on maximum demand days, by approximately 3.0 MVA.31 This amount of load reduction

31 This is an estimate only. The amount of load reduction required to defer the proposed augmentation will be finalised in a detailed

risk assessment.

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would need to be implemented by summer 2019-20 and be suitably located in the area that is presently supplied by DC zone substation under system normal configuration.

The estimated total annual cost of the preferred network option is $510,000. This provides a broad upper bound indication of the maximum contribution from UE which may be available to non-network service providers for deferring or avoiding the need for the proposed augmentation and eliminating all the energy-at-risk.

Next steps

UE intends to implement the preferred network solution in the absence of any commitment from interested parties to offer network support services by installing local generation or through demand management initiatives that would reduce the summer maximum demand at DC zone substation.

UE therefore invites interested parties to submit their proposal or to engage in joint planning with UE to defer to avoid the proposed network augmentation.

DC zone substation summary

DC zone substation




DC zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 1.00 1.00 1.00 1.00 1.00



Energy-at-risk (MWh) 640.1 788.4 884.8 948.9 1,006.9


Expected unserved energy (kWh) 2,388 2,942 3,301 3,540 3,757


Strategy



6.9.1.11 Dromana zone substation

Dromana (DMA) zone substation consists of two 20/33 MVA 66/22 kV transformers and supplies the areas of Dromana, Mount Martha, Red Hill and Shoreham.

DMA was commissioned in March 2006 with a single transformer to provide load relief for Rosebud (RBD) and Mornington (MTN) zone substations, as well as improving distribution feeder capacity and supply reliability in the area.

As foreshadowed in previous planning reports, the risk of supply interruption at DMA zone substation, for a single contingency event was assessed as being unacceptable. As a result, UE undertook a Regulatory Investment Test for Distribution (RIT-D) in 2014 to address the capacity limitations at DMA zone substation and the surrounding distribution feeder network. The RIT-D identified the installation of a second 20/33 MVA 66/22 kV transformer together with two new distribution feeders as the most economical solution. Therefore Dromana second transformer was commissioned in March 2016. This is reflected in the figure below.


DMA is a summer-critical zone substation. The actual maximum demand at DMA for summer 2015-16 was 39.3 MVA which occurred on 31 December 2015 at approximately 5:49 pm.

The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station’s summer (N) and nameplate ratings.

Figure 34 – Forecast maximum demand against station ratings for DMA zone substation

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Actual Demand Forecast Demand Summer (N) Rating

Summer (N-1) Rating Name Plate Rating

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The figure above shows that the maximum demand at DMA zone substation is expected to remain within its summer (N-1) rating over the next five years.

Therefore, on the basis of the current forecasts, no major demand related augmentation is planned at DMA zone substation over the next five years.

DMA zone substation summary

DMA zone substation




DMA zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 1.00 1.00 1.00 1.00 1.00





Expected unserved energy (MWh) 0 0 0 0 0


Strategy



6.9.1.12 Dandenong zone substation

Dandenong (DN) zone substation is fully developed with one 35/38 MVA 66/22 kV transformer and two 20/33 MVA 66/22 kV transformers. DN zone substation supplies the areas of Dandenong, Doveton, Endeavour Hills and Hallam. Two embedded generation schemes over 1 MW in the area help to reduce demand at DN on weekdays between 7:00 am and 11:00 pm. UE does not have network support agreements with these generators.

Being a designated Central Activities District, the demand in the Dandenong area is expected to continue to grow steadily over coming years, particularly as the economy recovers.

Due to age and deteriorating condition of the 35/38 MVA Transformer No.1 (manufactured in the late 1940s), UE plans to replace this transformer with modern equivalent transformer before summer 2018-19. The timing of this replacement is subject to updated asset information, re-alignment of other network projects and / or re-prioritisation of options to mitigate the deteriorating condition of the transformers.


DN is a summer-critical zone substation. The actual maximum demand at DN for summer 2015-16 was 75.4 MVA which occurred on 23 February 2016 at approximately 2:40 pm.

The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast (with and without embedded generation) together with the station’s summer (N) and (N-1) ratings.

Figure 35 – Forecast maximum demand against station ratings for DN zone substation

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Actual Demand With EG Forecast Demand With EG Summer (N) Rating

Actual Demand Without EG Forecast Demand Without EG Summer (N-1) Rating

Strategy



The figure above shows that with the embedded generation schemes out of service, the maximum demand at DN zone substation is expected to exceed its summer (N-1) rating from 2016-17. In the presence of the embedded generation schemes, the maximum demand at DN zone substation is not expected to exceed its summer (N-1) rating over the next five year period.



As shown above, if there is a forced transformer outage during summer maximum demand periods (without the embedded generation schemes in service), there will be insufficient capacity at DN zone substation to supply all demand in 2016-17 for about 12 hours.


Presently, there is only one 66 kV sub-transmission line circuit breaker at DN zone substation. Therefore, a forced outage of one of the sub-transmission line into DN zone substation could also lead to an outage of one of the DN zone substation transformers. However, the probability of such outage is low and the restoration time is expected to be shorter compared to a transformer outage. Therefore, the magnitude of expected unserved energy would be marginally higher than the values presented in the figure above.

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The following options are technically feasible and potentially economic to mitigate the risk of supply interruption and / or to alleviate the emerging limitations.


Plans to transfer load to adjacent zone substations at Dandenong Valley (DSH), Dandenong South (DSH), Keysborough (KBH) and Lyndale (LD) via the distribution feeder network are established. These plans are reviewed annually prior to the summer season. Transfer capability away from DN zone substation is assessed at 15.4 MVA for summer 2016-17.

2. Enter into a network support agreement.

UE may enter into network support agreement with the embedded generators connected at DN to reduce the energy-at-risk, when it becomes more significant.


There are no vacant zone substation sites in the area for a new 66/22 kV zone substation. However, this option is regarded as a long-term solution to supply the growing electricity demand in the area and could be economical in the future – ideally situated north of DN zone substation.


The risk assessment shows that the expected value of unserved energy is insufficient to justify augmentation within the next five years. Until a longer-term solution is implemented, UE proposes to maintain contingency plans to transfer load quickly to adjacent zone substation for an unplanned outage of a transformer at DN zone substation during critical loading conditions.

Therefore, on the basis of the current forecasts, no major demand related augmentation is planned at DN zone substation over the next five years.

Strategy



DN zone substation summary

DN zone substation




DN zone substation (With Generation) 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.99 0.99 0.99 0.99 0.99







DN zone substation (Without Generation) 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.99 0.99 0.99 0.99 0.99







Strategy



6.9.1.13 Dandenong South zone substation

Dandenong South (DSH) zone substation is developed with three 20/27 MVA 66/22 kV transformers and supplies the areas of Dandenong and Dandenong South.

Being a designated Central Activities District, the demand in the Dandenong area is expected to continue to grow steadily over coming years.

Due to age and deteriorating condition of the DSH transformers, UE plans to replace all three 20/27 MVA transformers (manufactured in the 1960s) with modern equivalent transformers before December 2018. The timing of this replacement is subject to updated asset information, re-alignment of other network projects and / or re-prioritisation of options to mitigate the deteriorating condition of the transformers.


DSH is a summer-critical zone substation. The actual maximum demand at DSH for summer 2015-16 was 57.2 MVA which occurred on 28 January 2016 at approximately 11:47 am.


Figure 37 – Forecast maximum demand against station ratings for DSH zone substation

The figure above shows that the actual maximum demand at DSH zone substation has been above its summer (N-1) rating in the last five years. After the two transformer replacement at DSH zone substation in 2018, the Summer N and N-1 rating of the DSH zone substation will slightly increases.

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The new Keysborough (KBH) zone substation has been commissioned and is fully in service. Although UE has transferred 7.5 MVA of DSH load onto KBH, in the figure above it is evident that the forecast maximum demand for summer 2016-17 at DSH is still greater than the N-1 rating because of recent growth.



As shown above, if there is a forced transformer outage during summer maximum demand periods (without the embedded generation schemes in service), there will be insufficient capacity at DSH zone substation to supply all demand in 2016-17 for about 266 hours.

It is emphasised that the probability of a major outage of a transformer occurring during summer maximum demand periods is very low – about 0.5% per transformer per year with the expected unavailability per transformer per year is about 0.37%. When the energy-at-risk is weighted by this low probability, the expected unserved energy is estimated to be 1,232 kWh in 2016-17. After the two transformer replacement at DSH, this figure is expected to reduce to 72 kWh in 2018-19, with the expected value of unserved energy of around $2,900 (based on a VCR of $40,550 per MWh).



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Plans to transfer load to adjacent zone substations at Dandenong Valley (DSH), Keysborough (KBH) and Dandenong (DN) via the distribution feeder network are established. These plans are reviewed annually prior to the summer season. Transfer capability away from DSH zone substation is assessed at 18.2 MVA for summer 2016-17.

2. Install new transformer at an adjacent zone substation.

Install a second transformer at KBH zone substation. Use distribution feeders at KBH to permanently offload DSH.

3. Install a fourth transformer at DSH zone substation.

Installation of a fourth 20/33 MVA 66/22 kV transformer would alleviate the capacity limitations at DSH zone substation.


The risk assessment shows that there is insignificant expected unserved energy over the next five years. Until a longer-term solution is implemented, to mitigate the risk of supply interruption and / or to alleviate the emerging limitations UE has established contingency plans to transfer load to adjacent zone substations at Dandenong (DN) and Dandenong Valley (DVY) via the distribution feeder network. These plans are reviewed annually prior to the summer season. Transfer capability away from DSH zone substation is assessed at 18.2 MVA for summer 2016-17.

Therefore, on the basis of the current forecasts, no major demand related augmentation is planned at DSH zone substation over the next five years.

Strategy



DSH zone substation summary

DSH zone substation

Summer (N) rating (MVA) 32 92 / 99

Summer (N-1) rating (MVA) 33 61 / 66


DSH zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.99 0.99 0.99 0.99 0.99





Expected unserved energy (kWh) 1,232 3,489 72 27 93

Expected value of unserved energy ($k) 50,000 141,500 2,900 1,100 3,800

32 Summer N rating will increase from summer 2018-19, after two transformer replacement at DSH. 33 Summer N-1 rating will increase from summer 2018-19, after two transformer replacement at DSH.

Strategy



6.9.1.14 Dandenong Valley zone substation

Dandenong Valley (DVY) zone substation consists of three 20/33 MVA 66/22 kV transformers and supplies the areas of Dandenong South and Lyndhurst.

A third 20/33 MVA 66/22 kV transformer was installed in 2011 to replace the 12/20 MVA 66/22 kV relocatable transformer (hot spare) which was stationed at DVY. The relocatable transformer has been moved to CDA zone substation.


DVY is a summer-critical zone substation. The actual maximum demand at DVY for summer 2015-16 was 78.3 MVA which occurred on 8 March 2016 at approximately 2:04 pm.


Figure 39 – Forecast maximum demand against station ratings for DVY zone substation

The figure above shows that the maximum demand at DVY zone substation is not expected to exceed its summer (N-1) rating over the next five year period.

There is no expected unserved energy over the next five years. Therefore, on the basis of the current forecasts, no major demand related augmentation is planned at DVY zone substation over the next five years.

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DVY zone substation summary

DVY zone substation




DVY zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.94 0.94 0.94 0.94 0.94







Strategy



6.9.1.15 East Burwood zone substation

East Burwood (EB) zone substation is fully developed with two 20/30 MVA 66/22 kV transformers and one 20/33 MVA 66/22 kV transformer and supplies the suburbs of Burwood East and Forest Hill.


EB is a summer-critical zone substation. The actual maximum demand at EB for summer 2015-16 was 58.4 MVA which occurred on 18 December 2015 at approximately 5:54 pm.


Figure 40 – Forecast maximum demand against station ratings for EB zone substation

The figure above shows that the maximum demand at EB zone substation is not expected exceed its summer (N-1) rating in the next five year planning period.

There is no expected unserved energy over the next five years. Therefore, on the basis of the current forecasts, no major demand related augmentation is planned at EB zone substation over the next five years.

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EB zone substation summary

EB zone substation




EB zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 1.00 1.00 1.00 1.00 1.00







Strategy



6.9.1.16 Elsternwick zone substation

Elsternwick (EL) zone substation consists of two 20/27 MVA 66/11 kV transformers and supplies the area of Elsternwick.

The 11 kV transformer cables were upgraded in 2012. This is reflected in the figure below.


EL is a summer-critical zone substation. The actual maximum demand at EL for summer 2015-16 was 28.9 MVA which occurred on 8 March 2016 at approximately 5:47 pm.


Figure 41 – Forecast maximum demand against station ratings for EL zone substation

The figure above shows that the maximum demand at EL zone substation is expected to exceed its summer (N-1) rating from 2016-17. However, the expected unserved energy is insignificant over the next five years.


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Strategy




As shown above, if there is a forced transformer outage during summer maximum demand periods (without the embedded generation schemes in service), there will be insufficient capacity at EL zone substation to supply all demand in 2016-17 for about 15 hours.





Plans to transfer load to adjacent zone substations at Caulfield (CFD), Elsternwick (EW) and North Brighton (NB) via the distribution feeder network are established. These plans are reviewed annually prior to the summer season. Transfer capability away from DSH zone substation is assessed at 6.3 MVA for summer 2016-17.


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Strategy



Install a new third 66/11 kV transformer at CFD, NB or EW zone substation along with distribution feeders to offload EL.

6. Install a third transformer at EL zone substation.

Installation of a third 20/33 MVA 66/22 kV transformer would alleviate the capacity limitations at EL zone substation.


The risk assessment shows that there is insignificant expected unserved energy over the next five years. Until a longer-term solution is implemented, to mitigate the risk of supply interruption and / or to alleviate the emerging limitations UE has established contingency plans to transfer load to adjacent zone substations at CFD, EW and NB via the distribution feeder network.

Therefore, on the basis of the current forecasts, no major demand related augmentation is planned at EL zone substation over the next five years.

Strategy



EL zone substation summary

EL zone substation




EL zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 1.00 1.00 1.00 1.00 1.00






Expected value of unserved energy ($) 700 1,700 3,700 2,200 1,900

Strategy



6.9.1.17 East Malvern zone substation

East Malvern (EM) zone substation consists of two 20/27 MVA 66/11 kV transformers and supplies the suburbs of Alamein, Carnegie, Chadstone and East Malvern.

Being a designated Principal Activities Centre, the demand around the Chadstone area is expected to continue to grow steadily over the coming years.


EM is a summer-critical zone substation. The actual maximum demand at EM for summer 2015-16 was 33.5 MVA which occurred on 19 December 2015 at approximately 5:22 pm.


Figure 43 – Forecast maximum demand against station ratings for EM zone substation

The figure above shows that with the exception of 2011-12 and 2014-15, the actual maximum demand at EM zone substation has been above its summer (N-1) rating. Given a modest demand growth over the next five years, there would be significant amount of energy-at-risk should a forced transformer outage occur during maximum demand periods.


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EM Summer Maximum Demand


Strategy




As shown above, if there is a forced transformer outage during summer maximum demand periods, there will be insufficient capacity at EM zone substation to supply all demand in 2016-17 for about 40 hours.


Presently, there are no 66 kV sub-transmission line circuit breakers at EM zone substation. Therefore, a forced outage of one of the sub-transmission line into EM zone substation would also lead to an outage of one of the EM zone substation transformers. However, the probability of such outage is low and the restoration time is expected to be shorter compared to a transformer outage. Therefore, the magnitude of expected unserved energy would be marginally higher than the values presented in the figure above.




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Plans to transfer load to adjacent zone substations at Oakleigh (OAK), Gardiner (K) and Ormond (OR) via the distribution feeder network are established. These plans are reviewed annually prior to the summer season. Transfer capability away from EM zone substation is assessed at 7.7 MVA for summer 2016-17.

2. Install a third transformer at EM.

Installation of a third 20/33 MVA 66/11 kV transformer would alleviate the capacity limitations at EM zone substation. This is most likely the least cost technically feasible network option for the long term as it would also resolve constraints existing at surrounding zone substations.


There are presently no sites under consideration to be developed as a new 66/11 kV zone substation to offload EM. The cost of acquiring a new site would very likely make such an option uneconomic unless initiated by the expansion of a major customer in the area.


The risk assessment shows that the expected value of unserved energy is insufficient to justify augmentation within the next five years. Until a longer-term solution is implemented, UE proposes to maintain contingency plans to transfer load quickly to adjacent zone substation for an unplanned outage of a transformer at EM zone substation during critical loading conditions.

Next steps

On the basis of the current forecasts, there appears to be no major demand related augmentation needed at EM zone substation over the next five years. However it is noted that a number of surrounding adjacent zone substations are also exhibiting load-at-risk and the combined total of these may be able to be alleviated economically by a 3rd transformer installed at EM just beyond the 5-year planning horizon. As such, UE is considering commencing a RIT-D consultation towards the end of 5-year planning horizon.

UE therefore invites interested parties to submit their proposal or to engage in joint planning with UE to defer to avoid the proposed network augmentation.

Strategy



EM zone substation summary

EM zone substation




EM zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 1.00 1.00 1.00 1.00 1.00







Strategy



6.9.1.18 Elwood zone substation

Elwood (EW) zone substation consists of two 20/30MVA 66/11kV transformers and supplies the area of Elwood.


EW is a summer-critical zone substation. The actual maximum demand at EW for summer 2015-16 was 20.3 MVA which occurred on 8 March 2016 at approximately 8:28 pm.


Figure 45 – Forecast maximum demand against station ratings at EW zone substation

The figure above shows that the maximum demand at EW zone substation is expected to remain within its summer (N-1) rating over the next five years.

Therefore, on the basis of the current forecasts, no major demand related augmentation is planned at EW zone substation over the next five years.

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EW zone substation summary

EW zone substation




EW zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 1.00 1.00 1.00 1.00 1.00







Strategy



6.9.1.19 Frankston South zone substation

Frankston South (FSH) zone substation is fully developed with one 20/27 MVA 66/22 kV transformer and two 20/33 MVA 66/22 kV transformers, and supplies the areas of Baxter, Frankston, Frankston South, Mount Eliza and Somerville.

During the January 2009 heatwave event, the existing Transformer No.1 and the old Transformer No.3 at FSH operated near their thermal limits of 140°C. These temperatures were reached despite the use of refrigerated cooling at the site, which effectively lowered the ambient temperature by 7°C. As a result, the paper insulation of the transformers was adversely affected causing premature aging. The poor conditions of the transformers were verified by tests undertaken in May 2009. Transformer No.3 in particular was identified as having reached the end of its useful engineering life, while Transformer No.1 is approaching its end of life and is anticipated to have around 10 years of life remaining. As a result, UE replaced the Transformer No.3 in 2011. There is no change to the station ratings at FSH as the full transformation capacity of Transformer No.2 and the new Transformer No.3 cannot be utilised until Transformer No.1 is replaced. The timing of this replacement is expected to be 2021-22.


FSH is a summer-critical zone substation. The actual maximum demand at FSH for summer 2015-16 was 63.0 MVA which occurred on 8 March 2016 at approximately 6:13 pm.


Strategy



Figure 46 – Forecast maximum demand against station ratings for FSH zone substation

The figure above shows that the actual maximum demand at FSH zone substation has been above its summer (N-1) rating in 2012-13, 2013-14 and 2015-16. Given absence of demand growth over the next five years, there would not be any incremental energy-at-risk should a forced transformer outage occur during maximum demand periods.


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FSH Summer Maximum Demand


Strategy




As shown above, if there is a forced transformer outage during summer maximum demand periods, there will be insufficient capacity at FSH zone substation to supply all demand in 2016-17 for about 40 hours.

It is emphasised that the probability of a major outage of a transformer occurring during summer maximum demand periods is very low – about 0.5% per transformer per year with the expected unavailability per transformer per year is about 0.37%. When the energy-at-risk is weighted by this low probability, the expected unserved energy is estimated to be 729 kWh in 2016-17. If no action is taken, this figure is expected to reduce to 572 kWh in 2020-21, with the expected value of unserved energy of around $23,200 (based on a VCR of $40,550 per MWh).

Presently, a 66 kV circuit breaker is installed on the MTN-FSH 66 kV sub-transmission line, but not on the TBTS-FSH 66 kV sub-transmission line. Therefore, a forced outage of the TBTS-FSH 66 kV line would also lead to an outage of one of the FSH zone substation transformers. Under such condition, the magnitude of the expected unserved energy would be higher than the values presented in the figure above.

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Plans to transfer load to adjacent zone substations at Frankston (FTN), Hastings (HGS), Langwarrin (LWN) and Mornington (MTN) via the distribution feeder network are established. These plans are reviewed annually prior to the summer season. Transfer capability away from FSH zone substation is assessed at 20.6 MVA for summer 2016-17. Works have been completed to allow the relocatable transformer to be connected at FSH should a major transformer fault occur.

2. Replace the FSH Transformer No.1 with modern equivalent.

Replace the FSH Transformer No.1 with modern equivalent transformer, as part of the asset replacement project. The timing of this replacement is expected to be before December 2021.


A third 66/22 kV transformer at Frankston (FTN) zone substation would address capacity constraints at FSH. However, long expensive distribution feeders would be required to reduce substantial load at FSH. A second 66/22 kV transformer at LWN offered the best solution by providing limited load relief for FSH while providing LWN with an (N-1) rating which reduces load-at-risk all year round. A second 20/33 MVA 66/22 kV transformer was installed at LWN zone substation in September 2014. As part of the LWN second transformer project, approximately 1 MVA was transferred away from FSH to LWN. The distribution feeder works could potentially be used to further offload FSH to LWN.


UE owns land in the Somerville area for a future 66/22 kV Somerville (SVE) zone substation, however development of this site is regarded as a longer-term solution to supply the growing electricity demand in the area and could be economical in future.


A second 20/33 MVA 66/22 kV transformer was installed at LWN zone substation in September 2014. Therefore, the distribution feeder works could potentially be used to offload FSH.

UE plans to replace the aged FSH Transformer No.1 with modern equivalent (20/33 MVA) transformer, as part of the asset replacement project, by 2021-22. It is anticipated that following the asset replacement, the station’s summer (N-1) rating is expected to be adequate to supply the maximum demand at FSH zone substation.

Until a longer-term solution is implemented, UE proposes to maintain contingency plans to transfer load quickly to adjacent zone substations for an unplanned outage of a transformer at FSH under critical loading conditions.

Strategy



Therefore, on the basis of the current forecasts, no major demand related augmentation is planned at FSH zone substation over the next five years.

FSH zone substation summary

FSH zone substation




FSH zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.99 0.99 0.99 0.99 0.99







Strategy



6.9.1.20 Frankston zone substation

Frankston (FTN) zone substation consists of two 20/33 MVA 66/22 kV transformers and supplies the areas of Frankston, Frankston North, Seaford and Skye.

In November 2009, a new zone substation was established in Langwarrin (LWN). This enabled load to be transferred from FTN to LWN.


FTN is a summer-critical zone substation. The actual maximum demand at FTN for summer 2015-16 was 51.3 MVA which occurred on 13 January 2016 at approximately 4:52 pm.


Figure 48 – Forecast maximum demand against station ratings for FTN zone substation

The figure above shows that with the exception of 2011-12, the actual maximum demand at FTN zone substation has been above its summer (N-1) rating. Given absence of demand growth over the next five years, there would not be any incremental energy-at-risk should a forced transformer outage occur during maximum demand periods.


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FTN Summer Maximum Demand


Strategy




As shown above, if there is a forced transformer outage during summer maximum demand periods, there will be insufficient capacity at FTN zone substation to supply all demand in 2016-17 for about 50 hours.

It is emphasised that the probability of a major outage of a transformer occurring during summer maximum demand periods is very low – about 0.5% per transformer per year with the expected unavailability per transformer per year is about 0.25%. When the energy-at-risk is weighted by this low probability, the expected unserved energy is estimated to be 606 kWh in 2016-17. If no action is taken, this figure is expected to rise to 584 kWh in 2020-21, with the expected value of unserved energy of $23,700 (based on a VCR of $40,550 per MWh).




Plans to transfer load to adjacent zone substations at Carrum (CRM), Frankston South (FSH), Dandenong Valley (DVY) and Langwarrin (LWN) via the distribution feeder network are established. These plans are reviewed annually prior to the summer season. Transfer capability away from FTN zone substation is assessed at 18.2 MVA for summer 2016-17.


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Carrum (CRM) zone substation is already fully developed with three transformers. Establishing new distribution feeders at CRM is expected to be challenging and costly given its close proximity to the Mornington Peninsula Freeway. Therefore, a second 66/22 kV transformer at LWN offered the best solution by providing limited load relief for FTN while providing LWN with an (N-1) rating which reduces load-at-risk all year round. A second 20/33 MVA 66/22 kV transformer was installed at LWN zone substation in September 2014. Therefore, the distribution feeder works could potentially be used to offload FTN.

3. Install a third transformer at FTN zone substation.

Installation of a third 20/33 MVA 66/22 kV transformer would alleviate the capacity limitations at FTN zone substation.


Establishing a new 66/22 kV Skye (SKE) zone substation with five new distribution feeders by 2030-31. Skye or Carrum Downs is identified as suitable locality for a new zone substation to offload Carrum zone substation (CRM) and partly FTN because it allows the distribution feeder lengths to be shortened, thereby improving distribution feeder utilisation and supply reliability in this area. Once commissioned, some load could be transferred away from FTN to SKE.

This new zone substation would be supplied via a new 66 kV sub-transmission line from CBTS, which is expected to offload the heavily loaded CBTS-CRM-FTN-FTS-LWN-CBTS system.


A second 20/33 MVA 66/22 kV transformer was installed at LWN zone substation in September 2014. Therefore, the distribution feeder works could potentially be used to offload FTN.

Based on the current maximum demand forecast for the area, no major demand related augmentation is planned at FTN zone substation over the next five years. Until a longer-term solution is implemented, UE proposes to maintain contingency plans to transfer load quickly to adjacent zone substations for an unplanned outage of a transformer at FTN under critical loading conditions.

Strategy



FTN zone substation summary

FTN zone substation




FTN zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 1.00 1.00 1.00 1.00 1.00







Strategy



6.9.1.21 Glen Waverley zone substation

Glen Waverley (GW) zone substation is developed with two 20/27 MVA 66/22 kV transformers and one 20/30 MVA 66/22 kV transformer and supplies the areas of Glen Waverley, Mount Waverley and Wantirna South.


GW is a summer-critical zone substation. The actual maximum demand at GW for summer 2015-16 was 62.6 MVA which occurred on 23 February 2016 at approximately 4:37 pm.


Figure 50 – Forecast maximum demand against station ratings for GW zone substation

The figure above shows that the maximum demand at GW zone substation is expected to exceed its summer (N-1) rating from 2016-17. Given flat demand over the next five years, there would not be a significant amount of incremental energy-at-risk should a forced transformer outage occur during maximum demand periods.


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GW Summer Maximum Demand


Strategy




As shown above, if there is a forced transformer outage during summer maximum demand periods, there will be insufficient capacity at GW zone substation to supply all demand in 2016-17 for about 9 hours.


Presently, there are no 66 kV sub-transmission line circuit breakers at GW zone substation. Therefore, a forced outage of one of the sub-transmission line into GW zone substation would also lead to an outage of one of the GW zone substation transformers. However, the probability of such outage is low and the restoration time is expected to be shorter compared to a transformer outage. Therefore, the magnitude of expected unserved energy would be marginally higher than the values presented in the figure above.

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Plans to transfer load to adjacent zone substations at East Burwood (EB), Mulgrave (MGE) and Notting Hill (NO) via the distribution feeder network are established. These plans are reviewed annually prior to the summer season. Transfer capability away from GW zone substation is assessed at 19.3 MVA for summer 2016-17.


Installing a third 20/33 MVA 66/22 kV transformer at Notting Hill (NO) zone substation together with two new distribution feeders is expected to be commissioned by December 2017. Once commissioned, distribution feeder works could potentially be used to offload GW.


There are presently no sites under consideration to be developed as a new 66/22 kV zone substation to offload GW. The cost of acquiring a new site would very likely make such an option uneconomic. However, this option is regarded as a long-term solution to supply the growing electricity demand in the area and could be economical in future, ideally situated in the Scoresby area.


Based on the current maximum demand forecast, UE intends to install a third 20/33 MVA 66/22 kV transformer at NO zone substation before December 2017. Once commissioned, distribution feeder works could potentially be used to offload GW to manage any increasing risk at this zone substation.

Until a longer-term solution is implemented, UE proposes to maintain contingency plans to transfer load quickly to adjacent zone substation for an unplanned outage of a transformer at GW zone substation during critical loading conditions.

Therefore, on the basis of the current forecasts, no major demand related augmentation is planned at GW zone substation over the next five years.

Strategy



GW zone substation summary

GW zone substation




GW zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 1.00 1.00 1.00 1.00 1.00







Strategy



6.9.1.22 Hastings zone substation

Hasting (HGS) zone substation consists of two 20/33 MVA 66/22 kV transformers and supplies the areas of Hasting, Merricks, Somerville and Tyabb.


HGS is a summer-critical zone substation. The actual maximum demand at HGS for summer 2015-16 was 46.9 MVA which occurred on 13 January 2016 at approximately 5:38 pm.


Figure 52 – Forecast maximum demand against station ratings for HGS zone substation

The figure above shows that the actual maximum demand at HGS zone substation has been above its summer (N-1) rating since 2010-11. Given a steady decline in demand growth over the next five years, there would not be a significant amount of energy-at-risk should a forced transformer outage occur during maximum demand periods.


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HGS Summer Maximum Demand


Strategy




As shown above, if there is a forced transformer outage during summer maximum demand periods, there will be insufficient capacity at HGS zone substation to supply all demand in 2016-17 for about 41 hours.

It is emphasised that the probability of a major outage of a transformer occurring during summer maximum demand periods is very low – about 0.5% per transformer per year with the expected unavailability per transformer per year is about 0.25%. When the energy-at-risk is weighted by this low probability, the expected unserved energy is estimated to be 419 kWh in 2016-17. This figure is expected to reduce to 265 kWh in 2019-20, with the expected value of unserved energy of around $10,800 (based on a VCR of $40,550 per MWh).

Presently, there are no 66 kV sub-transmission line circuit breakers at HGS zone substation. Therefore, a forced outage of one of the sub-transmission line into HGS zone substation would also lead to an outage of one of the HGS zone substation transformers. However, the probability of such outage is low and the restoration time is expected to be shorter compared to a transformer outage. Therefore, the magnitude of expected unserved energy would be marginally higher than the values presented in the figure above.

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Strategy






Plans to transfer load to adjacent zone substations at Frankston South (FSH), Langwarrin (LWN) and Mornington (MTN) via the distribution feeder network are established. These plans are reviewed annually prior to the summer season. Transfer capability away from HGS zone substation is assessed at 12.8 MVA for summer 2016-17.

2. Utilise distribution feeders of adjacent zone substation.

After the installation commissioning of second 20/33 MVA 66/22 kV transformer at Dromana (DMA) zone substation together with new distribution feeders in March 2016, distribution feeder works could potentially be used to offload HGS.

3. Install a third transformer at HGS zone substation.

Installation of a third 20/33 MVA 66/22 kV transformer would alleviate the capacity limitations at HGS zone substation.


UE currently owns a site in the Somerville area north of Hastings for a future 66/22 kV Somerville (SVE) zone substation. However, this option is regarded as a long-term solution to supply the growing electricity demand in the area and could be economical in future.


With the installation and commissioning of a second 20/33 MVA 66/22 kV transformer at DMA zone substation in March 2016, distribution feeder works could potentially be used to offload HGS. Additional load may be transferred from HGS to DMA by establishing new distribution feeder(s) at DMA. This is likely to defer the need for a third HGS transformer for some time in the future.

Until a longer term solution is implemented, UE proposes to maintain contingency plans to transfer load quickly to adjacent zone substations for an unplanned outage of a transformer at HGS under critical loading conditions.

Therefore, on the basis of the current forecasts, no major demand related augmentation is planned at HGS zone substation over the next five years.

Strategy



HGS zone substation summary

HGS zone substation




HGS zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 1.00 1.00 1.00 1.00 1.00







Strategy



6.9.1.23 Heatherton zone substation

Heatherton (HT) zone substation is developed with two 20/27 MVA 66/22 kV transformers and one 20/30 MVA 66/22 kV transformer and supplies the area of Heatherton.

Due to age and deteriorating condition of the 20/27 MVA Transformer No.2 and No.3 (manufactured in the 1960s), UE plans to replace these transformer with a modern equivalent transformers before December 2018. The timing of this replacement is subject to updated asset information, re-alignment of other network projects and / or re-prioritisation of options to mitigate the deteriorating condition of the transformers. Presently, the station’s summer (N) and (N-1) ratings are limited by transformers. Once replaced, the station’s summer ratings are expected to increase marginally.


HT is a summer-critical zone substation. The actual maximum demand at HT for summer 2015-16 was 50.8 MVA which occurred on 23 February 2016 at approximately 4:14 pm.


Figure 54 – Forecast maximum demand against station ratings for HT zone substation

The figure above shows that the maximum demand at HT zone substation is expected to remain within its summer (N-1) rating over the next five years.

Therefore, on the basis of the current forecasts, no major demand related augmentation is planned at HT zone substation over the next five years.

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HT zone substation summary

HT zone substation




HT zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.99 0.99 0.99 0.99 0.99







Strategy



6.9.1.24 Gardiner zone substation

Gardiner (K) zone substation consists of two 20/30 MVA 66/11 kV transformers and supplies the areas of Glen Iris and Malvern.

The 11 kV transformer cables on the existing Transformer No.3 were upgraded in 2011. This is reflected in the figure below.

Due to age and deteriorating condition of the existing 11 kV switchboard (manufactured in the early 1960s), UE plans to replace this switchboard with modern equivalent before December 2020. The timing of this replacement is subject to updated asset information, re-alignment of other network projects and / or re-prioritisation of options to mitigate the deteriorating condition of the switchboard.


K is a summer-critical zone substation. The actual maximum demand at K for summer 2015-16 was 41.8 MVA which occurred on 18 December 2015 at approximately 3:56 pm.


Figure 55 – Forecast maximum demand against station ratings for K zone substation

The figure above shows that the actual maximum demand at K zone substation has been above its summer (N-1) rating since 2011-12 except for 2014-15 (due to a mild summer). Given a flat demand over the next five years, there would not be any incremental energy-at-risk should a forced transformer outage occur during maximum demand periods.

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Strategy





As shown above, if there is a forced transformer outage during summer maximum demand periods, there will be insufficient capacity at K zone substation to supply all demand in 2016-17 for about 56 hours. To reduce the energy-at-risk, around 3.5 MVA load was permanently transferred from K to CFD zone substation in July 2016.


Presently, there are no 66 kV sub-transmission line circuit breakers at K zone substation. Therefore, a forced outage of one of the sub-transmission line into K zone substation would also lead to an outage of one of the K zone substation transformers. However, the probability of such outage is low and the restoration time is expected to be shorter compared to a transformer outage. Therefore, the magnitude of expected unserved energy would be marginally higher than the values presented in the figure above.

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Plans to transfer load to adjacent zone substations at Caulfield (CFD), Clarinda (CL) and East Malvern (EM) via the distribution feeder network are established. These plans are reviewed annually prior to the summer season. Transfer capability away from K zone substation is assessed at 8.8 MVA for summer 2016-17.


Install a third 20/33 MVA 66/11kV transformer at East Malvern (EM) zone substation. Once commissioned, distribution feeder works could potentially be used to offload K.

3. Install a third transformer at K zone substation.

Installation of a third 20/33 MVA 66/11 kV transformer will alleviate the capacity limitations at K zone substation.


There are no sites under consideration to be developed as a new 66/11 kV zone substation to offload K.


The risk assessment shows that the expected value of unserved energy is insufficient to justify augmentation within the next five years. Until a longer-term solution is implemented, UE proposes to maintain contingency plans to transfer load quickly to adjacent zone substation for an unplanned outage of a transformer at K zone substation during critical loading conditions.

Therefore, on the basis of the current forecasts, no major demand related augmentation is planned at K zone substation over the next five years.

Strategy



K zone substation summary

K zone substation




K zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 1.00 1.00 1.00 1.00 1.00







Strategy



6.9.1.25 Keysborough zone substation

Keysborough (KBH) zone substation consists of one 20/33 MVA 66/22 kV transformer and supplies the areas of Dandenong, Keysborough and Noble Park.

UE commissioned KBH zone substation in 2014-15 to provide load relief for Dandenong South (DSH), Mordialloc (MC) and Noble Park (NP) zone substations, as well as to improve distribution feeder utilisation and supply reliability in these areas.


KBH is a summer-critical zone substation. The actual maximum demand at KBH for summer 2015-16 was 26.3 MVA which occurred on 23 February 2016 at approximately 4:26 am.


Figure 57 – Forecast maximum demand against station ratings for KBH zone substation

The (N-1) rating at KBH zone substation is zero because it is a single transformer zone substation. Therefore, customers supply would be normally restored via the distribution feeder network from neighbouring zone substations at Dandenong South (DSH), Mordialloc (MC) and Noble Park (NP), following the loss of the zone substation transformer or other fault resulting in the total loss of supply to KBH.

KBH is designed to accept the 20 MVA relocatable transformer currently stationed at CDA zone substation as a hot spare. Whilst the probability of a transformer failure is very low, the energy at

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Actual Demand Forecast Demand Summer (N) Rating

Summer (N-1) Rating Name Plate Rating

Strategy



risk resulting from a transformer fault is high, because customers supplied from this substation are exposed to such an event all year round.

The figure above shows that the maximum demand at KBH zone substation is expected to remain within its nameplate rating over the next five years.



As shown above, customers supplied from KBH zone substation are exposed to an extended outage all year round, in the event of a major transformer outage.

The expected unserved energy is estimated to be 158 MWh in 2016-17. If no action is taken, this figure is expected to rise to 165 MWh in 2020-21, with the expected value of unserved energy of around $6.8M (based on a VCR of $40,550 per MWh).

It should be noted that the magnitude of expected unserved energy presented in the figure above are based on a high-level assessment. This assessment excludes the impact of load transfer capability to neighbouring zone substations at DSH, MC and NP. Had they been included, the magnitude of expected value of unserved energy would have been significantly lower than those values presented above. Such assessment will be undertaken in a Regulatory Investment Test for Distribution (RIT-D) at the appropriate time.

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Magnitude of load at risk above (N-1) and value of lost load at KBH



Strategy





1. Implement contingency plans to transfer load to adjacent zone substations

Plans to transfer load to adjacent zone substations at Dandenong South (DSH), Dandenong (DN), Lyndale (LD), Mordialloc (MC) and Noble Park (NP) via the distribution feeder network will be established. These plans are reviewed annually prior to the summer season. Transfer capability away from KBH zone substation is assessed at 30.6 MVA for summer 2016-17.

Plans to relocate the 20 MVA relocatable transformer from CDA to KBH should a major transformer outage occur during critical loading conditions.

2. Install a second transformer at KBH zone substation.

Installation of a second 20/33 MVA 66/22 kV transformer will alleviate the capacity limitations at KBH zone substation.

Preferred network option(s) for alleviation of limitation

Based on the current maximum demand forecast, a second 20/33 MVA 66/22 kV transformer at KBH zone substation is likely beyond the next five years. In the absence of any lower-cost options, this is the most likely least cost technically feasible network option.

Until a longer-term solution is implemented, UE proposes to maintain contingency plans to transfer load quickly to adjacent zone substation for an unplanned outage of a transformer at KBH zone substation during critical loading conditions.

Therefore, on the basis of the current forecasts, no major demand related augmentation is planned at KBH zone substation over the next five years.

Strategy



KBH zone substation summary

KBH zone substation




KBH zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.99 0.99 0.99 0.99 0.99



Energy-at-risk (MWh) 127,533 129,560 131,924 132,446 133,216

Hours at risk (hours) 8,752 8,752 8,752 8,752 8,752

Expected unserved energy (MWh) 158 161 164 164 165

Expected value of unserved energy ($k) 6,438 6,541 6,660 6,686 6,725

Strategy



6.9.1.26 Lyndale zone substation

Lyndale (LD) zone substation consists of two 20/30 MVA 66/22 kV transformers and one 20/33 MVA 66/22 kV transformer, and supplies the suburbs of Dandenong, Dandenong North, Endeavour Hills and Rowville.

A third 20/33 MVA 66/22 kV transformer was installed in 2012. This is reflected in the figure below.


LD is a summer-critical zone substation. The actual maximum demand at LD for summer 2015-16 was 52.2 MVA which occurred on 13 January 2016 at approximately 5:26 pm.


Figure 59 – Forecast maximum demand against station ratings for LD zone substation

The figure above shows that the maximum demand at LD zone substation is expected decline steadily and remain within its summer (N-1) rating over the next five years.

Therefore, on the basis of the current forecasts, no major demand related augmentation is planned at LD zone substation over the next five years.

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LD zone substation summary

The table below summarises information relating to LD zone substation.

LD zone substation




LD zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 1.00 1.00 1.00 1.00 1.00







Strategy



6.9.1.27 Langwarrin zone substation

Langwarrin (LWN) zone substation consists of two 20/33 MVA 66/22 kV transformers and supplies the areas of Cranbourne South, Langwarrin and Pearcedale.

LWN was commissioned in November 2009 as a single transformer zone substation to provide load relief for Frankston (FTN) and Frankston South (FSH) zone substations, as well as improving distribution feeder utilisation and supply reliability in these areas. Due to ongoing growth, a second 20/33 MVA 66/22 kV transformer was installed at LWN zone substation in September 2014. This is reflected in the figure below.


LWN is a summer-critical zone substation. The actual maximum demand at LWN for summer 2015-16 was 42.3 MVA which occurred on 13 January 2016 at approximately 5:51 pm.

The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the transformer nameplate ratings and the station’s summer (N) and (N-1) ratings.

Figure 60 – Forecast maximum demand against station ratings for LWN zone substation

The figure above shows that the maximum demand at LWN zone substation is expected to exceed its summer (N-1) rating from 2016-17. The expected unserved energy is insignificant over the next five years.

Therefore, on the basis of the current forecasts, no major demand related augmentation is planned at LWN zone substation over the next five years.

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LWN zone substation summary

LWN zone substation




LWN zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.99 0.99 0.99 0.99 0.99







Strategy



6.9.1.28 Mentone zone substation

Mentone (M) zone substation consists of two 20/27 MVA 66/11 kV transformers and one 20/33 MVA 66/11 kV transformer, and supplies the suburbs of Mentone and Parkdale.

A third 20/33 MVA 66/11 kV transformer was installed in 2013. This is reflected in the figure below.

Due to age and deteriorating condition of the 20/27 MVA Transformer No.2 (manufactured in the 1960s), UE plans to replace this transformer with a modern equivalent transformer after December 2023. The timing of this replacement is subject to updated asset information, re-alignment of other network projects and / or re-prioritisation of options to mitigate the deteriorating condition of the transformers.


M is a summer-critical zone substation. The actual maximum demand at M for summer 2015-16 was 35.7 MVA which occurred on 13 January 2016 at approximately 5:26 pm.


Figure 61 – Forecast maximum demand against station ratings for M zone substation

The figure above shows that the maximum demand at M zone substation is expected to remain within its summer (N-1) rating over the next five years.

Therefore, on the basis of the current forecasts, no major demand related augmentation is planned at M zone substation over the next five years.

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M zone substation summary

M zone substation




M zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.99 0.99 0.99 0.99 0.99







Strategy



6.9.1.29 Mordialloc zone substation

Mordialloc (MC) zone substation is fully developed with two 20/27 MVA 66/22 kV transformers and one 20/33 MVA 66/22 kV transformer and supplies the areas of Aspendale, Braeside, Edithvale and Mordialloc.

Due to age and deteriorating condition of the two 20/27 MVA transformers (manufactured in the late 1950s), UE plans to replace them with new modern equivalent transformers before December 2022. As part of this replacement, UE also plans to replace the existing 22 kV outdoor switchyard with an indoor switchboard. Once replaced, the station’s summer ratings are expected to be adequate to meet the maximum demand at MC zone substation over the next five years. The timing of this replacement is subject to updated asset information, re-alignment of other network projects and / or re-prioritisation of options to mitigate the deteriorating condition of the transformers.


MC is a summer-critical zone substation. The actual maximum demand at MC for summer 2015-16 was 53.5 MVA which occurred on 23 February 2016 at approximately 2:45 pm.


Figure 62 – Forecast maximum demand against station ratings for MC zone substation

The figure above shows that the actual maximum demand at MC zone substation has been above its summer (N-1) rating since 2011-12 except for the last two years and also the new Keysborough

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(KBH) zone substation was commissioned in September 2014, so some load was transferred from MC zone substation to KBH zone substation. This transfer is reflected in the demand forecast shown above.

Despite this transfer, the maximum demand at MC zone substation is expected to remain above its summer (N-1) rating. Given a flat demand over the next five years, there would not be any incremental energy-at-risk should a forced transformer outage occur during maximum demand periods.



As shown above, if there is a forced transformer outage during summer maximum demand periods, there will be insufficient capacity at MC zone substation to supply all demand in 2016-17 for about 113 hours.


Presently, there are no 66 kV sub-transmission line circuit breakers at MC zone substation. Therefore, a forced outage of one of the sub-transmission line into MC zone substation would also

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lead to an outage of one of the MC zone substation transformers. However, the probability of such outage is low and the restoration time is expected to be shorter compared to a transformer outage. Therefore, the magnitude of expected unserved energy would be marginally higher than the values presented in the figure above.




Plans to transfer load to adjacent zone substations at Carrum (CRM), Noble Park (NP) and Springvale South (SS) via the distribution feeder network are established. These plans are reviewed annually prior to the summer season. Transfer capability away from MC zone substation is assessed at 18.9 MVA for summer 2016-17. Works have been completed to allow the relocatable transformer to be connected should a major transformer fault occur.

2. Replace the existing MC transformers.

Replace the existing 20/27 MVA transformers with modern equivalent (20/33 MVA) transformers before December 2022.


There are no vacant zone substation sites in the area for a new 66/22 kV zone substation. However, this option is regarded as a long-term solution to supply growing electricity demand in the area as well as catering for potential significant development in this area. This zone substation could be economical in the future – ideally situated at or near Moorabbin Airport in Mordialloc or at Dingley.


UE intends to replace the existing 20/27 MVA 66/22 kV transformers with modern equivalent (20/33 MVA) 66/22 kV transformers before summer 2022-23. Once replaced, it is expected that the station’s (N-1) rating would be adequate to supply the maximum demand at MC zone substation.

Until a longer term solution is implemented, UE proposes to maintain contingency plans to transfer load quickly to adjacent zone substations for an unplanned outage of a transformer at MC under critical loading conditions.

Therefore, on the basis of the current forecasts, no major demand related augmentation is planned at MC zone substation over the next five years.

Strategy



MC zone substation summary

MC zone substation




MC zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.98 0.98 0.98 0.98 0.98







Strategy



6.9.1.30 Mulgrave zone substation

Mulgrave (MGE) zone substation is fully developed with three 20/33 MVA 66/22 kV transformers and supplies the areas of Mulgrave, Rowville, Scoresby and Wheelers Hill.


MGE is a summer-critical zone substation. The actual maximum demand at MGE for summer 2015-16 was 73.2 MVA which occurred on 23 February 2016 at approximately 4:30 pm.


Figure 64 – Forecast maximum demand against station ratings for MGE zone substation

The figure above shows that with the exception of 2011-12, 2014-15 and 2015-16, the actual maximum demand at MGE zone substation has been above its summer (N-1) rating. Given a steady demand growth over the next five years, there would be significant amount of energy-at-risk should a forced transformer outage occur during maximum demand periods.


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As shown above, if there is a forced transformer outage during summer maximum demand periods, there will be insufficient capacity at MGE zone substation to supply all demand in 2016-17 for about 49 hours.

It is emphasised that the probability of a major outage of a transformer occurring during summer maximum demand periods is very low – about 0.5% per transformer per year with the expected unavailability per transformer per year is about 0.37%. When the energy-at-risk is weighted by this low probability, the expected unserved energy is estimated to be 655 kWh in 2016-17. If no action is taken, this figure is expected to rise to 1,549 kWh in 2020-21, with the expected value of unserved energy of around $62,800 (based on a VCR of $40,550 per MWh).

Presently, there are no 66 kV sub-transmission line circuit breakers at MGE zone substation. Therefore, a forced outage of one of the sub-transmission line into MGE zone substation would also lead to an outage of one of the MGE zone substation transformers. However, the probability of such outage is low and the restoration time is expected to be shorter compared to a transformer outage. Therefore, the magnitude of expected unserved energy would be marginally higher than the values presented in the figure above.




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Plans to transfer load to adjacent zone substations at Glen Waverley (GW), Lyndale (LD) and Springvale West (SVW) via the distribution feeder network are established. These plans are reviewed annually prior to the summer season. Transfer capability away from MGE is assessed at 19.3 MVA for summer 2016-17.

2. Permanent load transfer.

Some load could be transferred from MGE zone substation to LD zone substation, where a third transformer was installed in December 2012.


There are no vacant zone substation sites in the area for a new 66/22 kV zone substation. However, this option is regarded as a long-term solution to supply the growing electricity demand in the area and could be economical in the future – ideally situated in the Scoresby area. This could also facilitate the growing and emerging limitations in AusNet Electricity Services’ distribution service areas of Knoxfield and Rowville.


Based on the current maximum demand forecast, UE intends to consider further load transfer options to LD and maintain contingency plans to transfer load quickly to adjacent zone substations for an unplanned outage of a transformer at MGE under critical loading conditions.

Strategy



MGE zone substation summary

MGE zone substation




MGE zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 1.00 1.00 1.00 1.00 1.00





Expected unserved energy (kWh) 655 929 1,525 1,442 1,549


Strategy



6.9.1.31 Moorabbin zone substation

Moorabbin (MR) zone substation consists of two 20/33 MVA 66/11 kV transformers. MR zone substation supplies the suburbs of Brighton, Hampton East and Moorabbin.


MR is a summer-critical zone substation. The actual maximum demand at MR for summer 2015-16 was 43.4 MVA which occurred on 8 March 2016 at approximately 5:30 pm.


Figure 66 – Forecast maximum demand against station ratings for MR zone substation

The figure above shows that the maximum demand at MR zone substation is expected to exceed its summer (N-1) rating from summer 2016-17. However, the expected unserved energy is insignificant over the next five years.


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As shown above, if there is a forced transformer outage during summer maximum demand periods (without the embedded generation schemes in service), there will be insufficient capacity at MR zone substation to supply all demand in 2016-17 for about 63 hours.





Plans to transfer load to adjacent zone substations at Sandringham (SR), Bentleigh (BT), Ormond (OR) and North Brighton (NB) via the distribution feeder network are established. These plans are reviewed annually prior to the summer season. Transfer capability away from DSH zone substation is assessed at 9.1 MVA for summer 2016-17.

2. Install a third transformer at MR zone substation.

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Installation of a third 20/33 MVA 66/22 kV transformer would alleviate the capacity limitations at MR zone substation.


The risk assessment shows that there is insignificant expected unserved energy over the next five years. Until a longer-term solution is implemented, to mitigate the risk of supply interruption and / or to alleviate the emerging limitations UE has established contingency plans to transfer load to adjacent zone substations via the distribution feeder network.

Therefore, on the basis of the current forecasts, no major demand related augmentation is planned at MR zone substation over the next five years.

MR zone substation summary

MR zone substation




MR zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 1.00 1.00 1.00 1.00 1.00







Strategy



6.9.1.32 Mornington zone substation

Mornington (MTN) zone substation consists of two 20/33 MVA 66/22 kV transformers and supplies the areas of Merricks North, Moorooduc and Mornington.

MTN previously consisted of three 10MVA 66/22kV transformers and one 20/33 MVA 66/22 kV transformer. MTN was a rural type zone substation and did not have transformer or bus-tie circuit breakers. This was a low cost design, whereby a transformer or bus fault resulted in a complete outage of the zone substation until the faulty component can be found and isolated. However, this arrangement has changed with the MTN redevelopment project and the zone substation was converted into a fully switched configuration in early 2013. Further, as part of the MTN redevelopment project, three old 10 MVA 66/22 kV transformers were replaced with a new 20/33MVA 66/22kV transformer. This is reflected in the figure below.


MTN is a summer-critical zone substation. The actual maximum demand at MTN for summer 2015-16 was 54.2 MVA which occurred on 8 March 2016 at approximately 6:02 pm.


Figure 68 – Forecast maximum demand against station ratings for MTN zone substation

The figure above shows that except for 2012-13, the actual maximum demand at MTN zone substation has been above its summer (N-1) rating since 2011-12. Given a flat demand over the

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next five years, there would not any incremental energy-at-risk should a forced transformer outage occur during maximum demand periods.



As shown above, if there is a forced transformer outage during summer maximum demand periods, there will be insufficient capacity at MTN zone substation to supply all demand in 2016-17 for about 50 hours.


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Plans to transfer load to adjacent zone substations at Dromana (DMA), Frankston South (FSH) and Hastings (HGS) via the distribution feeder network are established. These plans are reviewed annually prior to the summer season. Transfer capability away from MTN is assessed at 15.5 MVA for summer 2016-17.

2. Permanent Load transfer to an adjacent zone substation.

After the commissioning of a second 20/33 MVA 66/22 kV transformer at DMA together with new distribution feeders in March 2016, distribution feeder works could potentially be used to offload MTN.

3. Install a third transformer at MTN zone substation.

Installing a third 20/33 MVA 66/22 kV transformer will alleviate the capacity constraints at MTN zone substation.


There are presently no sites under consideration to be developed as a new 66/22 kV zone substation to offload MTN. The cost of acquiring a new site would very likely make such an option uneconomic when lower-cost alternatives are available.


UE has installed a second 20/33 MVA 66/22 kV transformer at DMA zone substation together with new distribution feeders commissioned in March 2016. The distribution feeder works could potentially be used to offload MTN.

Based on the current maximum demand forecast, a third 20/33 MVA 66/22 kV transformer at MTN zone substation is likely beyond the next five years. In the absence of any lower-cost options, this is the most likely least cost technically feasible network option.

Until a longer term solution is implemented, UE proposes to maintain contingency plans to transfer load quickly to adjacent zone substations for an unplanned outage of a transformer at MTN under critical loading conditions.

Therefore, on the basis of the current forecasts, no major demand related augmentation is planned at MTN zone substation over the next five years.

Strategy



MTN zone substation summary

MTN zone substation




MTN zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 1.00 1.00 1.00 1.00 1.00







Strategy



6.9.1.33 North Brighton zone substation

North Brighton (NB) zone substation is fully developed with two 20/33 MVA 66/11 kV transformers and supplies the areas of Brighton and North Brighton.

NB is a very old zone substation. Due to the conditions of the previous transformers (manufactured in the early 1950s), UE replaced them with new 20/33 MVA transformers in 2012. As a result, the station’s summer ratings have increased marginally as illustrated in the figure below. The station ratings are now limited by the 11 kV switchboards. Due to age and deteriorating condition of this switchboard, UE plans to replace it with modern equivalent before June 2017. Once replaced, the station’s summer ratings are expected to increase marginally. The timing of this replacement may change subject to updated asset information, re-alignment of other network projects and / or re-prioritisation of options to mitigate the deteriorating condition of the transformers.


NB is a summer-critical zone substation. The actual maximum demand at NB for summer 2015-16 was 43.9 MVA which occurred on 8 March 2016 at approximately 6:24 pm.


Figure 70 – Forecast maximum demand against station ratings for NB zone substation

The figure above shows that except for summer 2014-15, the actual maximum demand at NB zone substation has been above its summer (N-1) rating since 2011-12. Given a flat demand growth

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over the next five years, there would not be a significant amount of incremental energy-at-risk should a forced transformer outage occur during maximum demand periods.



As shown above, if there is a forced transformer outage during summer maximum demand periods, there will be insufficient capacity at NB zone substation to supply all demand in 2016-17 for about 71 hours.

It is emphasised that the probability of a major outage of a transformer occurring during summer maximum demand periods is very low – about 0.5% per transformer per year with the expected unavailability per transformer per year is about 0.25%. When the energy-at-risk is weighted by this low probability, the expected unserved energy is estimated to be 1,057 kWh in 2016-17. This figure is expected to reduce to 908 kWh in 2020-21, with the expected value of unserved energy of around $36,800 (based on a VCR of $40,550 per MWh).

Presently, there are no 66 kV sub-transmission line circuit breakers at NB zone substation. Therefore, a forced outage of one of the sub-transmission line into NB zone substation would also lead to an outage of one of the NB zone substation transformers. However, the probability of such outage is low and the restoration time is expected to be shorter compared to a transformer outage. Therefore, the magnitude of expected unserved energy would be marginally higher than the values presented in the figure above.

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Plans to transfer load to adjacent zone substations at Bentleigh (BT), Elsternwick (EL), Elwood (EW) and Moorabbin (MR) via the distribution feeder network are established. These plans are reviewed annually prior to the summer season. Transfer capability away from NB zone substation is assessed at 11.3 MVA for summer 2016-17.

2. Replace the existing 11 kV switchboard and circuit breakers.

Replace the existing 11 kV switchboard with modern equivalent before June 2017.


There are no sites under consideration to be developed as a new 66/11 kV zone substation to offload NB.


UE intends to replace the aged 11 kV switchboard and circuit breakers with modern equivalent by June 2017. Once replaced, the station’s summer (N-1) rating is expected to increase marginally.

Until a longer term solution is implemented, UE proposes to maintain contingency plans to transfer load quickly to adjacent zone substations for an unplanned outage of a transformer at NB under critical loading conditions.

Therefore, on the basis of the current forecasts, no major demand related augmentation is planned at NB zone substation over the next five years.

Strategy



NB zone substation summary

NB zone substation




NB zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.99 0.99 0.99 0.99 0.99





Expected unserved energy (kWh) 1,057 1,002 971 906 908

Expected value of unserved energy ($) 42,900 40,700 39 ,400 36,800 36,800

Strategy



6.9.1.34 Notting Hill zone substation

Notting Hill (NO) zone substation consists of two 20/30 MVA 66/22 kV transformers and supplies the area of Notting Hill.


NO is a summer-critical zone substation. The actual maximum demand at NO for summer 2015-16 was 44.1 MVA which occurred on 13 January 2016 at approximately 2:33 pm.


Figure 72 – Forecast maximum demand against station ratings for NO zone substation

The figure above shows that the actual maximum demand at NO zone substation has been above its summer (N-1) rating since 2011-12. Given a high demand growth over the next five years, there would be significant amount of energy-at-risk should a forced transformer outage occur during maximum demand periods.


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As shown above, if there is a forced transformer outage during summer maximum demand periods, there will be insufficient capacity at NO zone substation to supply all demand in 2016-17 for about 313 hours.

It is emphasised that the probability of a major outage of a transformer occurring during summer maximum demand periods is very low – about 0.5% per transformer per year with the expected unavailability per transformer per year is about 0.25%. When the energy-at-risk is weighted by this low probability, the expected unserved energy is estimated to be 3,642 kWh in 2016-17. If no action is taken, this figure is expected to rise to 23.8 MWh in 2020-21, with the expected value of unserved energy of around $1.0M (based on a VCR of $40,550 per MWh).34

Presently, there are no 66 kV sub-transmission line circuit breakers at NO zone substation. Therefore, a forced outage of one of the sub-transmission line into NO zone substation would also lead to an outage of one of the NO zone substation transformers. However, the probability of such outage is low and the restoration time is expected to be shorter compared to a transformer outage. Therefore, the magnitude of expected unserved energy would be marginally higher than the values presented in the figure above.



34 This is an estimate only and does not include the neighboring zone substation and feeder risk. The amount of expected unserved energy is detailed in the RIT-D assessments.

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Plans to transfer load to adjacent zone substations at Glen Waverley (GW) and Springvale West (SVW) via the distribution feeder network are established. These plans are reviewed annually prior to the summer season. Transfer capability away from NO is assessed at 11.5 MVA for summer 2016-17.

2. Install a third transformer at NO zone substation.

Installation of a third 20/33 MVA 66/22 kV transformer at NO would alleviate the capacity limitations at NO zone substation. As part of this project, two new distribution feeders are likely to be established to improve the distribution feeder utilisation, supply reliability and to cater for new developments in the area. The cost of this augmentation is estimated at $5.1 million.

3. Establish a new 66/22 kV zone substation.

There are presently no sites under consideration to be developed as a new 66/22 kV zone substation to offload NO. The cost of acquiring a new site would very likely make such an option uneconomic when lower-cost options are available.

Preferred network solution for alleviation of limitations

UE started a RIT-D consultation process in April 2016 to resolve the limitations within the Notting Hill electricity supply area. Based on the detailed RIT-D assessment, UE recommended to install a third 20/33 MVA 66/22 kV transformer at NO zone substation together with two new distribution feeders. The most economic timing for this project is before December 2017. The cost of this network solution is around $5.1 million. No alternate lower-cost option was identified during the RIT-D consultation process.

This augmentation shall:

Address capacity limitations at NO zone substation;

Address capacity limitations in the distribution feeders; and

Improve poor supply reliability in the area.

Until the preferred solution is implemented, UE proposes to maintain contingency plans to transfer load quickly to adjacent zone substation for an unplanned outage of a transformer at NO zone substation under critical loading conditions.

Once a third transformer is installed at NO by December 2017, the maximum demand at NO zone substation is expected to remain within its new (N-1) rating over the next five years.

Strategy



NO zone substation summary

NO zone substation




NO zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.97 0.97 0.97 0.97 0.97



Energy-at-risk (MWh) 1,463 2,630 6,043 7,862 9,555

Hours at risk (hours) 313 637 1,615 1,878 2,071

Expected unserved energy (MWh) 3.7 6.6 15.1 19.6 23.8

Expected value of unserved energy ($k) 148 266 610 794 965

Strategy



6.9.1.35 Noble Park zone substation

Noble Park (NP) zone substation is fully developed with three 20/30 MVA 66/22 kV transformers and supplies the areas of Keysborough and Noble Park.

The new Keysborough (KBH) zone substation has been commissioned so some load has been transferred from NP to KBH. This is reflected in the graph below.

Due to age and deteriorating condition of the 20/30 MVA Transformer No.1 and Transformer No.2 (manufactured in the 1960s), UE plans to replace them with new modern equivalent transformers before summer 2027-28. Once replaced, the station’s summer (N-1) rating is expected to increase marginally. The timing of this replacement is subject to updated asset information, re-alignment of other network projects and / or re-prioritisation of options to mitigate the deteriorating condition of the transformers.


NP is a summer-critical zone substation. The actual maximum demand at NP for summer 2015-16 was 58.5 MVA which occurred on 13 January 2016 at approximately 5:22 pm.


Figure 74 – Forecast maximum demand against station ratings for NP zone substation

The figure above shows that the actual maximum demand at NP zone substation has been below its summer (N-1) for most of the years since 2011-12. Following load transfers to the new KBH

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zone substation, the maximum demand at NP zone substation is expected to remain within its (N-1) rating over the next five years.

Therefore, on the basis of the current forecasts, no major demand related augmentation is planned at NP zone substation over the next five years.

NP zone substation summary

NP zone substation




NP zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 1.00 1.00 1.00 1.00 1.00







Strategy



6.9.1.36 Nunawading zone substation

Nunawading (NW) zone substation is fully developed with three 20/33 MVA 66/22 kV transformers and supplies the areas of Blackburn, Donvale and Nunawading.


NW is a summer-critical zone substation. The actual maximum demand at NW for summer 2015-16 was 60.6 MVA which occurred on 18 December 2015 at approximately 4:14 pm.


Figure 75 – Forecast maximum demand against station ratings for NW zone substation

The figure above shows that the maximum demand at NW zone substation is expected to remain within its (N-1) rating over the next five years.

Therefore, on the basis of the current forecasts, no major demand related augmentation is planned at NW zone substation over the next five years.

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NW zone substation summary

NW zone substation




NW zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.99 0.99 0.99 0.99 0.99







Strategy



6.9.1.37 Oakleigh zone substation

Oakleigh (OAK) zone substation consists of two 20/33 MVA 66kV/11 kV transformers and supplies the areas of Chadstone, Mt Waverley and Oakleigh.

One of the transformers is a relocatable 66/11 kV transformer (hot spare) that can be used at another 66/11 kV zone substation following a major transformer outage during critical loading conditions.

Being a designated Principal Activities Centre, the maximum demand around the Chadstone area is expected to continue to grow steadily.


OAK is a summer-critical zone substation. The actual maximum demand at OAK for summer 2015-16 was 37.9 MVA which occurred on 19 December 2015 at approximately 3:57 pm.


Figure 76 – Forecast maximum demand against station ratings for OAK zone substation

The figure above shows that the maximum demand at OAK zone substation is expected to exceed its (N-1) rating from 2018-19. However the energy at risk is not significant over the next five years.

Therefore, on the basis of the current forecasts, no major demand related augmentation is planned at OAK zone substation over the next five years.

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OAK zone substation summary

OAK zone substation




OAK zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 1.00 1.00 1.00 1.00 1.00







Strategy



6.9.1.38 Oakleigh East zone substation

Oakleigh East (OE) zone substation consists of two 20/30 MVA 66/11 kV transformers and supplies the suburbs of Huntingdale and Oakleigh East.


OE is a summer-critical zone substation. The actual maximum demand at OE for summer 2015-16 was 13.5 MVA which occurred on 18 December 2015 at approximately 1:45 pm.


Figure 77 – Forecast maximum demand against station ratings for OE zone substation

The figure above shows that the maximum demand at OE zone substation is expected to remain within its (N-1) rating over the next five years.

Therefore, on the basis of the current forecasts, no major demand related augmentation is planned at OE zone substation over the next five years.

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OE zone substation summary

OE zone substation




OE zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.89 0.89 0.89 0.89 0.89







Strategy



6.9.1.39 Ormond zone substation

Ormond (OR) zone substation consists of two 20/27 MVA 66/11 kV transformers and supplies the areas of Bentleigh East, Hughesdale and Murrumbeena.


OR is a summer-critical zone substation. The actual maximum demand at OR for summer 2015-16 was 35.8 MVA which occurred on 13 January 2016 at approximately 5:36 pm.


Figure 78 – Forecast maximum demand against station ratings for OR zone substation

The figure above shows that the actual maximum demand at OR zone substation has been above its summer (N-1) rating in the last few years. Given a flat demand growth over the next five years, there would not be significant amount of incremental energy-at-risk should a forced transformer outage occur during maximum demand periods.


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As shown above, if there is a forced transformer outage during summer maximum demand periods, there will be insufficient capacity at OR zone substation to supply all demand in 2016-17 for about 15 hours.


Presently, there are no 66 kV sub-transmission line circuit breakers at OR zone substation. Therefore, a forced outage of one of the sub-transmission line into OR zone substation would also lead to an outage of one of the OR zone substation transformers. However, the probability of such outage is low and the restoration time is expected to be shorter compared to a transformer outage. Therefore, the magnitude of expected unserved energy would be marginally higher than the values presented in the figure above.

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Plans to transfer load to adjacent zone substations at Bentleigh (BT), Caulfield (CFD), East Malvern (EM) and Oakleigh East (OE) via the distribution feeder network are established. These plans are reviewed annually prior to the summer season. Transfer capability away from OR is assessed at 6.8 MVA for summer 2016-17.

2. Install a third transformer at OR zone substation.

Installation of a third 20/33 MVA 66/11 kV transformer will alleviate the capacity limitations at OR zone substation.

3. Install a third transformer at EM zone substation.

Installation of a third 20/33 MVA 66/11 kV transformer at EM and load transfers from OR to EM will alleviate the capacity limitations at OR zone substation.


There are presently no sites under consideration to be developed as a new 66/11 kV zone substation to offload OR. The cost of acquiring a new site would very likely make such an option uneconomic when lower-cost alternatives are available.


The risk assessment shows that the expected value of unserved energy is insufficient to justify augmentation within the next five years. Until a longer term solution is implemented, UE proposes to maintain contingency plans to transfer load quickly to adjacent zone substations for an unplanned outage of a transformer at OR under critical loading conditions.

Therefore, on the basis of the current forecasts, no major demand related augmentation is planned at OR zone substation over the next five years.

Strategy



OR zone substation summary

OR zone substation




OR zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.98 0.98 0.98 0.98 0.98







Strategy



6.9.1.40 Rosebud zone substation

Rosebud (RBD) zone substation consists of two 20/33 MVA 66/22 kV transformers and supplies the areas of Arthurs Seat, Cape Schanck, Flinders and Rosebud.

RBD previously had three 10 MVA 66/22 kV transformers which were 50 years old. It was a low cost rural design without transformer or bus-tie circuit breakers, whereby a transformer or bus fault resulted in a complete loss of the zone substation until the faulty component is found and isolated. One of the 10 MVA transformers was replaced with a new 20/33 MVA transformer in December 2010 and the station was rebuilt to a fully switched zone substation with a second 20/33 MVA transformer in 2011.


RBD is a summer-critical zone substation. The actual maximum demand at RBD for summer 2015-16 was 40.2 MVA which occurred on 31 December 2015 at approximately 5:43 pm.


Figure 80 – Forecast maximum demand against station ratings for RBD zone substation

The figure above shows that the maximum demand at RBD zone substation is expected to exceed its summer (N-1) rating from 2018-19.


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As shown above, if there is a forced transformer outage during summer maximum demand periods, there will be insufficient capacity at RBD zone substation to supply all demand in 2018-19 for about 3 hour.

It is emphasised that the probability of a major outage of a transformer occurring during summer maximum demand periods is very low – about 0.5% per transformer per year with the expected unavailability per transformer per year is about 0.25%. When the energy-at-risk is weighted by this low probability, the expected unserved energy is estimated to be 1 kWh in 2018-19. If no action is taken, this figure is expected to rise to 17 kWh in 2020-21, with the expected value of unserved energy of around $700 (based on a VCR of $40,550 per MWh).




Plans to transfer load to adjacent zone substations at Dromana (DMA) and Sorrento (STO) via the distribution feeder network are established. These plans are reviewed annually prior to the summer season. Transfer capability away from RBD is assessed at 22.1 MVA for summer 2016-17.

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After the commissioning of a second 20/33 MVA 66/22 kV transformer at DMA together with new distribution feeders, the distribution feeder works could potentially be used to offload RBD.

3. Install a third transformer at RBD zone substation.

Installing a third 20/33 MVA 66/22 kV transformer would alleviate the capacity constraints at RBD zone substation.


There are presently no sites under consideration to be developed as a new 66/22 kV zone substation to offload RBD. The cost of acquiring a new site would very likely make such an option uneconomic when lower-cost alternatives are available.


The risk assessment shows that the expected value of unserved energy is insufficient to justify augmentation within the next five years. Until a longer-term solution is implemented, UE proposes to maintain contingency plans to transfer load quickly to adjacent zone substation for an unplanned outage of a transformer at RBD zone substation during critical loading conditions.

Therefore, on the basis of the current forecasts, no major demand related augmentation is planned at RBD zone substation over the next five years.

Strategy



RBD zone substation summary

RBD zone substation




RBD zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 1.00 1.00 1.00 1.00 1.00







Strategy



6.9.1.41 Surrey Hills zone substation

Surrey Hills (SH) zone substation consists of two 10 MVA 22kV/6.6 kV transformers and supplies the areas of Surrey Hills.

SH is a very old zone substation. Due to age and deteriorating condition of the existing transformers (manufactured in the 1950s), UE plans to replace Transformer No.1 and No.3 with modern equivalent transformer before summer 2020-21. The timing of these replacements is subject to updated asset information, re-alignment of other network projects and / or re-prioritisation of options to mitigate the deteriorating condition of the transformers. An alternative approach is the retirement of these transformers and the conversion of the SH distribution network to 22 kV.

In 2014-15 UE has replaced the existing 6.6 kV switchboard with new switchboard capable of operating at 11 kV or 22 kV (in anticipation of future conversion to 11 kV or 22 kV).


SH is a summer-critical zone substation. The actual maximum demand at SH for summer 2015-16 was 6.8 MVA which occurred on 19 December 2015 at approximately 5:28 pm.


Figure 82 – Forecast maximum demand against station ratings for SH zone substation

The figure above shows that the maximum demand at SH zone substation is expected to remain within its summer (N-1) rating over the next five years.

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Therefore, on the basis of the current forecasts, no major demand related augmentation is planned at SH zone substation over the next five years.

SH zone substation summary

SH zone substation




SH zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.97 0.97 0.97 0.97 0.97







Strategy



6.9.1.42 Sandringham zone substation

Sandringham (SR) zone substation consists of two 20/27 MVA 66/11 kV transformers and supplies the areas of Highett and Sandringham. Transformer cables which once limited the station’s capacity were replaced in 2011 resulting in an increase in the station’s capacity.


SR is a summer-critical zone substation. The actual maximum demand at SR for summer 2015-16 was 32.1 MVA which occurred on 19 December 2015 at approximately 4:52 pm.


Figure 83 – Forecast maximum demand against station ratings for SR zone substation

The figure above shows that the maximum demand at SR zone substation is remains below its summer (N-1) rating over the next five years.

Therefore, on the basis of the current forecasts, no major demand related augmentation is planned at SR zone substation over the next five years.

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SR zone substation summary

SR zone substation




SR zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 1.00 1.00 1.00 1.00 1.00







Strategy



6.9.1.43 Springvale South zone substation

Springvale South (SS) zone substation consists of two 20/33 MVA 66/22 kV transformers and supplies the area of Dingley and Springvale South.

Two embedded generation schemes over 1 MW in the area reduce demand at SS on weekdays between 7:00 am and 11:00 pm. UE does not currently have network support agreements with these generators.


SS is a summer-critical zone substation. The actual maximum demand at SS for summer 2015-16 was 36.1 MVA which occurred on 13 January 2016 at approximately 5:03 pm.


Figure 84 – Forecast maximum demand against station ratings for SS zone substation

The figure above shows that with or without the embedded generation schemes in service, the maximum demand at SS zone substation is expected to exceed its summer (N-1) rating over the next five years.


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Actual Demand With EG Forecast Demand With EG Summer (N) Rating

Actual Demand Without EG Forecast Demand Without EG Summer (N-1) Rating

Strategy




A forced transformer outage during summer maximum periods (with the embedded generation schemes out-of-service), there will be insufficient capacity at SS zone substation to supply all demand in 2016-17 for about 49 hours.

When the energy-at-risk is weighted by this low probability, the expected unserved energy is estimated to be 313 kWh in 2016-17. If no action is taken, this figure is expected to rise to 315 kWh in 2020-21, with the expected value of unserved energy of around $12,800 (based on a VCR of $40,550 per MWh).

Presently, there are no 66 kV sub-transmission line circuit breakers at SS zone substation. Therefore, a forced outage of one of the sub-transmission line into SS zone substation would also lead to an outage of one of the SS zone substation transformers. However, the probability of such outage is low and the restoration time is expected to be shorter compared to a transformer outage. Therefore, the magnitude of expected unserved energy would be marginally higher than the values presented in the figure above.




Plans to transfer load to adjacent zone substations at Nobel Park (NP), Heatherton (HT), Mordialloc (MC) and Springvale (SV) via the distribution feeder network are

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established. These plans are reviewed annually prior to the summer season. Transfer capability away from SS is assessed at 22.6 MVA for summer 2016-17.


There are no plans to install a new transformation at an adjacent zone substation. However, UE plans to replace the existing 20/27 MVA transformers at Mordialloc (MC) with new 20/33 MVA transformers before summer 2022-23. This is expected to increase MC summer ratings. Once replaced, distribution feeder works could potentially be used to offload SS.

3. Enter into a network support agreement.

UE may enter into network support agreement with the embedded generators connected at SS to reduce the energy-at-risk, when it becomes more significant.

4. Install a third transformer at SS zone substation.

Installation of a third 20/33 MVA 66/22 kV transformer will alleviate the capacity limitation at SS zone substation.


There presently no sites under consideration planned to be developed as a new 66/22 kV zone substation to offload SS. However, it may be necessary to establish a new 66/22 kV zone substation at or near Moorabbin Airport in Mordialloc or Dingley beyond the next five years to cater for potential significant growth in the area.


UE intends to replace the aged 20/27 MVA transformers at Mordialloc (MC) zone substation with 20/33 MVA transformers before summer 2022-23. Once replaced, distribution feeder works could potentially be used to offload SS. Additional load may be transferred from SS to MC by installing new distribution feeder(s) at MC. This could defer the need for a third SS transformer for some time in the future.

Until a longer term solution is implemented, UE proposes to maintain contingency plans to transfer load quickly to adjacent zone substations for an unplanned outage of a transformer at SS under critical loading conditions.

Therefore, on the basis of the current forecasts, no major demand related augmentation is planned at SS zone substation over the next five years.

Strategy



SS zone substation summary

SS zone substation




SS zone substation (With Generation) 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.94 0.94 0.94 0.94 0.94







SS zone substation (Without Generation) 2015-16 2016-17 2017-18 2018-19 2019-20


Power factor 0.94 0.94 0.94 0.94 0.94







Strategy



6.9.1.44 Sorrento zone substation

Sorrento (STO) zone substation consists of two 20/33 MVA 66/22 kV transformers and supplies the areas of Blairgowrie, Portsea, Rye and Sorrento.

The maximum demand at STO normally occurs during the Christmas and New Year holiday periods due to increased activities along the tip of the Mornington Peninsula.

One embedded generation scheme over 1 MW is connected within the STO supply area. This scheme is brought into service as and when required by the customer.


STO is a summer-critical zone substation. The actual maximum demand at STO for summer 2015-16 was 41.0 MVA which occurred on 31 December 2015 at approximately 5:55 pm.


Figure 86 – Forecast maximum demand against station ratings for STO zone substation

The figure above shows that the actual maximum demand at STO zone substation has been above its summer (N-1) for most of the years since 2011-12. Given a steady demand growth over the next five years, there would be significant amount of energy-at-risk should a forced transformer outage occur during maximum demand periods.


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As shown above, if there is a forced transformer outage during summer maximum demand periods, there will be insufficient capacity at STO zone substation to supply all demand in 2016-17 for about 7 hours.


Presently, there are no 66 kV sub-transmission line circuit breakers or a 66kV bus-tie circuit breaker at STO zone substation. Therefore, a forced outage of one of the sub-transmission line into STO zone substation would also lead to an outage of one of the STO zone substation transformers. However, the probability of such outage is low and the restoration time is expected to be shorter compared to a transformer outage. Therefore, the magnitude of expected unserved energy would be marginally higher than the values presented in the figure above.

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Plans to transfer load to adjacent zone substations at Dromana (DMA) and Rosebud (RBD) via the distribution feeder network are established. These plans are reviewed annually prior to the summer season. Transfer capability away from STO is assessed at 14.4 MVA for summer 2016-17.

2. Install a third transformer at STO zone substation.

Installation of a third 20/33 MVA 66/22 kV transformer would alleviate the capacity limitations at STO zone substation.


There are no sites under consideration to be developed as a new 66/22 kV zone substation to offload STO.


The risk assessment shows that the expected value of unserved energy is insufficient to justify augmentation within the next five years. Until a longer-term solution is implemented, UE proposes to maintain contingency plans to transfer load quickly to adjacent zone substation for an unplanned outage of a transformer at STO zone substation during critical loading conditions.

Therefore, on the basis of the current forecasts, no major demand related augmentation is planned at STO zone substation over the next five years.

Strategy



STO zone substation summary

STO zone substation




STO zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.99 0.99 0.99 0.99 0.99







Strategy



6.9.1.45 Springvale and Springvale West zone substations

Springvale (SV) zone substation was previously fully developed with three 20/33 MVA 66/22 kV transformers. However, in 2007 UE established a new zone substation adjacent to SV called Springvale West (SVW) to support the growing industrial demand, where one of the existing SV transformers and capacitor banks were transferred from SV to SVW. Under system-normal, both SV and SWV have two 20/33 MVA 66/22 kV transformers, one 22 kV capacitor bank and two 22 kV buses each.

SV and SVW are considered as a single zone substation in this report because SV is linked to SVW via a high capacity 22 kV bus tie cable rated at over 45 MVA and the SV and SVW distribution feeders are interleaved. Following the loss of a transformer at either SV or SVW, an automatic bus-tie close control circuit immediately closes the normally-open bus-tie circuit breaker, joining the two zone substations into one. It is therefore more meaningful to consider SV and SVW together.

SV and SVW zone substations supply the areas of Springvale, Clayton and the Monash University precinct in Clayton North.


SV/SVW is a summer-critical zone substation. The actual maximum demand at SV/SVW for summer 2015-16 was 102.0 MVA which occurred on 23 February 2016 at approximately 3:40 pm.


Figure 88 – Forecast maximum demand against station ratings for SV/SVW zone substation

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The figure above shows that the maximum demand at SV/SVW zone substation is expected to exceed its summer (N-1) rating from 2016-17.



As shown above, if there is a forced transformer outage during summer maximum demand periods, there will be insufficient capacity at SV/SVW zone substation to supply all demand in 2017-18 for about 4 hour.


Presently, there are no 66 kV sub-transmission line circuit breakers at SV/SVW zone substation. Therefore, a forced outage of one of the sub-transmission line into SV/SVW zone substation would also lead to an outage of one of the SV/SVW zone substation transformers. However, the probability of such outage is extremely low and the restoration time is expected to be shorter compared to a transformer outage. Therefore, the magnitude of expected unserved energy would be marginally higher than the values presented in the figure above.

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SV and SVW supply a number of customers with high security requirements and therefore those customers have a dual supply with primary and back-up supplies from independent 22 kV distribution feeders and zone substations. To provide this backup, UE must reserve spare capacity on the network just in case it is needed for these customers. The amount of capacity available for other network users is therefore reduced. SV must provide a total reserve capacity of 25.1 MVA and SVW 9.0 MVA for summer 2016-17.




Plans to transfer load to adjacent zone substations at Nobel Park (NP), Mulgrave (MGE), Notting Hill (NO) and Springvale South (SS) via the distribution feeder network are established. These plans are reviewed annually prior to the summer season. Transfer capability away from SV and SVW is assessed at 18.3 MVA for summer 2016-17.


Installing a third 20/33 MVA 66/22 kV transformer at NO together with new distribution feeders is expected to be commissioned before December 2017. Once commissioned, distribution feeder works could potentially be used to offload SV/SVW.

3. Install a third 66/22 kV transformer at SV or SVW zone substation.

Installation of a third 20/33 MVA 66/22 kV transformer at SV or SVW will alleviate the capacity limitations at SV/SVW zone substation. As part of this project, new distribution feeders shall be established to improve the distribution feeder utilisation and supply reliability in the area.


There are presently no sites under consideration to be developed as a new 66/22 kV zone substation to offload SV/SVW. The cost of acquiring a new site would very likely make such an option uneconomic.


UE intends to augment NO with a third 20/33 MVA 66/22 kV transformer together with two new distribution feeders before summer 2017-18. Once commissioned, distribution feeder works could potentially be used to offload SV/SVW. Additional load may be transferred from SV/VW to NO by installing new distribution feeder(s) at NO. This is likely to defer the need for a third transformer at SV or SVW for some time in the future.

Until a longer term solution is implemented, UE proposes to maintain contingency plans to transfer load quickly to adjacent zone substations for an unplanned outage of a transformer at SV/SVW under critical loading conditions.

Strategy



Therefore, on the basis of the current forecasts, no major demand related augmentation is planned at SV/SVW zone substation over the next five years.

SV/SVW zone substation summary

SV/SVW zone substation




SV/SVW zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 1.00 1.00 1.00 1.00 1.00






Expected value of unserved energy ($) 100 1,100 6,500 8,200 9,400

Strategy



6.9.1.46 West Doncaster zone substation

West Doncaster (WD) zone substation is fully developed with two 20/27 MVA 66/11 kV transformers and one 20/30 MVA 66/11 kV transformer and supplies the areas of North Balwyn, Doncaster and the Doncaster Hill precinct.

Due to age and deteriorating condition of the 20/30 MVA Transformer No.2 (manufactured in the late 1960s), UE plans to replace this transformer with a new modern equivalent transformer before summer 2028-29. The timing of this replacement is subject to updated asset information, re-alignment of other network projects and / or re-prioritisation of options to mitigate the deteriorating condition of the transformers.


WD is a summer-critical zone substation. The actual maximum demand at WD for summer 2015-16 was 48.6 MVA which occurred on 19 December 2015 at approximately 5:20 pm.


Figure 90 – Forecast maximum demand against station ratings for WD zone substation

The figure above shows that the maximum demand at WD zone substation is expected to remain within its summer (N-1) rating over the next five years.

Therefore, on the basis of the current forecasts, no major demand related augmentation is planned at WD zone substation over the next five years.

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WD zone substation summary

WD zone substation




WD zone substation 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.99 0.99 0.99 0.99 0.99







Strategy



6.9.2 Sub-transmission systems

6.9.2.1 CBTS sub-transmission system

There is currently one UE 66 kV sub-transmission system connected to Cranbourne Terminal Station (CBTS) that supplies three UE zone substations. The system is:

1. CBTS-CRM-FTN-FTS-LWN-CBTS

CBTS-CRM-FTN-FTS-LWN-CBTS

The CBTS-CRM-FTN-FTS-LWN-CBTS 66 kV sub-transmission system supplies Carrum (CRM), Langwarrin (LWN) and Frankston (FTN) zone substations as shown in the figure below. Frankston Terminal Station (FTS) is a switching station (i.e. no transformation) and is owned and operated by AusNet Transmission Group.

Figure 91 – CBTS-CRM-FTN-FTS-LWN-CBTS sub-transmission system

CBTS

FTS

CRM

LWN

FTN

In 2009, LWN zone substation was inserted into this sub-transmission system. As part of the LWN zone substation project, United Energy upgraded its existing CBTS-CRM 66 kV line in 2009 to increase this sub-transmission system (N) and (N-1) ratings.

Strategy



The ownership of the 66 kV assets supplying CRM, FTN and LWN zone substations is listed in the table below.

Table 20 – Network ownership arrangement

66 kV lines Ownership

CBTS-FTS No.1 line Transmission connection asset owned by AusNet Transmission Group

CBTS-FTS No.2 line Transmission connection asset owned by AusNet Transmission Group

CBTS-CRM line Distribution asset owned by UE

FTS-FTN line Distribution asset owned by UE

FTS-LWN line Distribution asset owned by UE

CRM-FTN-LWN line Distribution asset owned by UE

The critical limitation on this sub-transmission system is currently the CBTS-FTS 66 kV lines for an outage of the CBTS-CRM 66 kV line during maximum demand conditions. Under this condition, AusNet Transmission Group’s automatic load shedding scheme would be initiated to trip both lines. This would result in loss of electricity supply to all customers connected at CRM, FTN and LWN zone substations until the lines are re-energised with sufficiently reduced demand to avoid further overloading. Similarly, for an outage of the CBTS-CRM 66 kV line, the CBTS-FTN-LWN 66 kV line would become overloaded.

There is an inflight project to implement dynamic line ratings on the CBTS-FTS 66kV double circuit tower lines using actual wind velocity, which is planned to be completed in 2017-18.


CBTS-CRM-FTN-FTS-LWN-CBTS is a summer-critical sub-transmission system. The actual maximum demand on this system for summer 2015-16 was 1,516 Amps which occurred on 13 January 2016 at approximately 5:37 pm.

The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the sub-transmission system’s operational summer (N) and (N-1) ratings.

Strategy



Figure 92 – Forecast maximum demand against CBTS-CRM-FTN-FTS-LWN-CBTS system ratings

The figure above shows that the maximum demand on the CBTS-CRM-FTN-FTS-LWN-CBTS sub-transmission is expected to exceed its summer (N-1) rating in 2016-17. AusNet Transmission Group will be implementing dynamic ratings for the CBTS-FTS 66kV lines by 2017-18. This will bring maximum demand on the CBTS-CRM-FTN-FTS-LWN-CBTS sub-transmission below its summer (N-1) rating until 2020-21.

The bar chart below depicts the expected unserved energy for the CBTS-CRM-FTN-FTS-LWN-CBTS sub-transmission system following the loss of the CBTS-CRM 66 kV line under the 10% PoE demand forecast and the hours per year that the 10% PoE demand is expected to exceed the system’s summer (N-1) rating. The line graph shows the expected value of unserved energy in each year, for the 10% PoE demand forecast.

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Actual Load Forecast Load Summer (N-1) rating Summer (N) rating

Strategy




As shown above, if there is a forced outage of the CBTS-CRM 66 kV line during summer maximum demand conditions, there will be insufficient capacity in this sub-transmission system to supply all demand in 2016-17.

From summer 2021-22, to protect assets from overloading, centralised automatic load shedding scheme (SOCS) at CBTS for CBTS-FTS two 66kV lines would need to be implemented to ensure that the loading of these two lines do not exceed their dynamic ratings. If SOCS is not implemented to manage the loading of the two CBTS-FTS 66 kV lines below their dynamic ratings, AusNet Transmission Group will protect its assets by tripping both CBTS-FTS 66 kV lines. Hence there is a risk of the total supply to FTS being disconnected for an outage of the CBTS-CRM 66 kV line during high demand periods when the total connected load exceeds the N-1 rating. This can result in loss of electricity supply to all customers connected at CRM, FTN and LWN zone substations. In such an event, it is anticipated that the CBTS-FTS 66 kV lines can be re-energised within two hours after ensuring sufficient demand reduction to avoid further overloading.



1. Maintain contingency plan to transfer load to adjacent sub-transmission systems and the use of dynamic line ratings

Plans to transfer load to adjacent sub-transmission systems via the distribution feeder network are established. These plans are reviewed annually prior to the

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Hours at risk above N-1 Expected energy above N-1 Expected Value of Unserved Energy

Strategy



summer season. Transfer capability away from this system is assessed at 36.7 MVA for summer 2016-17.

2. Implement dynamic rating for CBTS-FTS No.1 and CBTS-FTS No.2 66 kV lines and centralised automatic load shedding scheme (SOCS) at CBTS for CBTS-FTS 66kV two lines

AusNet Transmission Group will be implementing dynamic ratings for the CBTS-FTS 66kV lines by 2017-18. This will elevate network limitation until 2020-21. Beyond 2021-22, to protect assets from overloading, centralised automatic load shedding scheme (SOCS) at CBTS for CBTS-FTS two 66kV lines would be implemented to ensure that the loading of these two lines do not exceed their dynamic ratings.

3. Establish a new 66 kV line from CBTS

Installation of a new 66 kV line from CBTS (approximately 11 km) to connect the existing CRM-FTN-LWN 66 kV line will alleviate the capacity constraints on this sub-transmission system.

4. Establish a new zone substation with a new 66 kV sub-transmission system

Establishing a new 66/22 kV Skye (SKE) zone substation with five new distribution feeders by 2030-31. Skye or Carrum Downs is identified as suitable locality for a new zone substation to offload CRM because it allows the distribution feeder lengths to be shortened, thereby improving distribution feeder utilisation and supply reliability in this area.

The new zone substation would be supplied from a new sub-transmission line from CBTS. Once commissioned, the existing sub-transmission system would be offloaded by transferred load away from CRM and FTN zone substations to the new SKE zone substation.

The estimated cost of this augmentation is $26 million. The sub-transmission connection portion of works is estimated at $12 million while the zone substation establishment portion of works is estimated at $14 million.


AusNet Transmission Group will implement dynamic ratings for the CBTS-FTS 66kV lines by 2017-18. This will elevate network limitation until 2020-21. Beyond 2021-22, to protect assets from overloading, AusNet Transmission Group will implement centralised automatic load shedding scheme (SOCS) at CBTS for CBTS-FTS two 66kV lines would be implemented to ensure that the loading of these two lines do not exceed their dynamic ratings.

Based on the current maximum demand forecast, no major demand related augmentation is planned for this system over the next five years. UE proposes to maintain contingency plans to transfer load quickly to adjacent sub-transmission systems for an unplanned outage of critical section of this system under critical loading conditions.

Strategy



CBTS-CRM-FTN-FTS-LWN-CBTS system summary

CBTS-CRM-FTN-LWN-FTS-CBTS system

Summer cyclic ‘N’ Rating (MVA) 251

Summer cyclic ‘N-1’ Rating (MVA) 184

Embedded generator capacity (MVA) 11.8

CBTS-CRM-FTN-LWN-FTS-CBTS system 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.95 0.95 0.95 0.95 0.95



N-1 energy at risk at 10% PoE demand (MWh) 0 0 0 0 1

N-1 expected hours at risk at 10% PoE demand (hours) 1 0 0 0 1

N-1 expected energy at risk at 10% PoE demand (kWh) 59 0 0 0 848

Expected unserved energy at 10% PoE demand ($) 2,400 0.0 0.0 0.0 34,400

Strategy



6.9.2.2 ERTS sub-transmission systems

There are currently two 66 kV sub-transmission systems connected to East Rowville Terminal Station (ERTS) that supply five UE zone substations. The systems are:

1. ERTS-DN-DSH-DVY-HPK-ERTS

2. ERTS-LD-MGE-ERTS

ERTS-DN-DSH-DVY-HPK-ERTS

The ERTS-DN-DSH-DVY-HPK-ERTS sub-transmission system is a shared system between UE and AusNet Electricity Services that supplies Dandenong (DN), Dandenong South (DSH) and Dandenong Valley (DVY) zone substations as well as AusNet Electricity Services’ Hampton Park (HPK) zone substation as shown below. Planning on this system is therefore a joint responsibility.

Embedded generation schemes in the area helps to reduce demand at DN and HPK zone substations.

Figure 94 – ERTS-DN-DSH-DVY-HPK-ERTS sub-transmission system

ERTS

DSH

DVY

DN

HPK

Strategy



Prior to 2010, ERTS-DN-HPK-ERTS and ERTS-DSH-DVY-ERTS were two independent sub-transmission systems. Due to capacity limitations on both systems, UE established a 66 kV tie-line from DN to DSH-DVY in December 2010 to link the two systems together. As part of the second stage of this augmentation, a new 66 kV line from ERTS to the DN-HPK line was established by AusNet Electricity Services in December 2012 to provide a longer-term solution for both systems.

The ownership of the 66 kV assets supplying DN, DSH, DVY and HPK zone substations are listed in the table below.


66 kV lines Ownership

ERTS-DN line Distribution asset owned by UE

ERTS-DSH line Distribution asset owned by UE

ERTS-DVY line Distribution asset owned by UE

ERTS-HPK line Distribution asset owned by AusNet Electricity Services

ERTS-HPK-DN line Distribution asset owned by UE between DN and HPK

Distribution asset owned by AusNet Electricity Services between ERTS and the tee point

DN-DSH-DVY line Distribution asset owned by UE


ERTS-DN-DSH-DVY-HPK-ERTS is a summer-critical sub-transmission system. The actual maximum demand on this system for summer 2015-16 was 2,030 Amps which occurred on 13 January 2016 at approximately 1:41 pm.


Strategy



Figure 95 – Forecast maximum demand against ERTS-DN-DSH-DVY-HPK-ERTS system ratings

The figure above shows that the maximum demand on the ERTS-DN-HPK/DSH-DVY-ERTS sub-transmission system is expected to remain within its summer (N-1) rating over the next five years.

Therefore, on the basis of the current forecasts, no major demand related augmentation is planned for this system over the next five years.

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Actual Load with Generation Forecast Load with Generation

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Actual Load without Generation Forecast Load without Generation

Strategy



ERTS-DN-DSH-DVY-HPK-ERTS system summary

ERTS-DSH-DVY-DN-HPK-ERTS system




ERTS-DSH-DVY-DN-HPK-ERTS system (With Gen) 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.95 0.95 0.95 0.95 0.95






Expected unserved energy at 10% PoE demand ($k) 0.0 0.0 0.0 0.0 0.0

ERTS-DSH-DVY-DN-HPK-ERTS system (Without Gen) 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.95 0.95 0.95 0.95 0.95







Strategy



ERTS-LD-MGE-ERTS

ERTS-LD-MGE-ERTS 66kV sub-transmission system supplies Lyndale (LD) and Mulgrave (MGE) zone substations in a looped arrangement.

The critical limitation on this sub-transmission system is currently the ERTS-MGE 66 kV line for an outage of the ERTS-LD 66 kV line during maximum demand conditions. Similarly, for an outage of the ERTS-MGE 66 kV line, the ERTS-LD 66 kV line would become overloaded.


ERTS-LD-MGE-ERTS is a summer-critical sub-transmission system. The actual maximum demand on this system for summer 2015-16 was 1,089 Amps which occurred on 13 January 2016 at approximately 5:27 pm.


Figure 96 – Forecast maximum demand against ERTS-LD-MGE-ERTS system ratings

The figure above shows that with the exception of 2011-12, 2014-15 and 2015-16, the actual maximum demand on the ERTS-LD-MGE-ERTS sub-transmission system has been above its summer (N-1) rating. Given a flat demand growth forecast over the next five years, there will not be a significant amount of energy-at-risk if critical sections of this system are out-of-service during maximum demand conditions.

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The bar chart below depicts the expected unserved energy for the ERTS-LD-MGE-ERTS sub-transmission system following the loss of critical sections of this system for the 10% PoE maximum demand forecast and the hours per year that the 10% PoE maximum demand forecast is expected to exceed the system’s summer (N-1) rating. The line graph shows the expected value of unserved energy in each year, for the 10% PoE summer maximum demand forecast.


As shown above, if there is a forced outage of critical sections of this sub-transmission system during summer maximum demand conditions, there will be insufficient capacity in this sub-transmission system to supply all demand in 2016-17 for about 7 hours.

It is emphasised that the probability of a major sub-transmission line outage occurring during summer maximum demand periods is very low. When the energy-at-risk is weighted by this low probability, the expected unserved energy is estimated to be 8 kWh in 2016-17. If no action is taken, this figure is expected to rise to 18 kWh in 20120-21, with the expected value of unserved energy of around $710 (based on a VCR of $40,550 per MWh).



1. Maintain contingency plan to transfer load to adjacent sub-transmission systems and the use of dynamic line ratings


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Strategy




2. Upgrade the ERTS-MGE and ERTS-LD 66 kV circuits

These lines were upgraded to standard 66 kV overhead conductors in 2009. Therefore, any further capacity upgrade would require larger non-standard conductors and augmentation of line circuit breakers to suit the higher rating.

3. Establish new 66 kV line from ERTS

Installation of a new 66 kV line from ERTS (approximately 3.5 km) to connect the existing MGE-LD 66 kV line will alleviate the capacity constraints on this sub-transmission system.

4. Establish a new zone substation with a separate sub-transmission system

Establishing the 66/22 kV Scoresby (SCY) zone substation with new distribution feeders is regarded as a long-term solution to supply the growing electricity demand in this area. Scoresby is identified as suitable locality for a new zone substation to offload Mulgrave (MGE) zone substation and its sub-transmission system, facilitate the growing demand. This new zone substation shall also facilitate the growing and emerging limitations in AusNet Electricity Services’ distribution areas of Knoxfield and Rowville.

The new zone substation could be supplied from a new sub-transmission system from ERTS or integrated into an augmented ERTS-BGE-FGY-ERTS sub-transmission system currently owned by AusNet Electricity Services in the area. Once commissioned, the ERTS-LD-MGE-ERTS sub-transmission system shall be offloaded by transferred load away from MGE zone substation to the new SCY zone substation.


Based on the current maximum demand forecast, UE intends to maintain contingency plans to transfer load quickly to adjacent zone substations for an unplanned outage of a transformer at MGE under critical loading conditions.


Strategy



ERTS-LD-MGE-ERTS system summary

ERTS-MGE-LD-ERTS system




ERTS-MGE-LD-ERTS system 2015-16 2016-17 2017-18 2018-19 2019-20


Power factor 0.95 0.95 0.95 0.95 0.95






Expected unserved energy at 10% PoE demand ($) 340 389 603 588 711

Strategy



6.9.2.3 HTS sub-transmission systems

There are currently three UE 66 kV sub-transmission systems connected to Heatherton Terminal Station (HTS) that supply ten UE zone substations. The three systems are:

1. HTS-BR-KBH-M-MC-HTS

2. HTS-MR-BT-NB-HTS

3. HTS-HT-CM-SR-HTS

HTS-BR-KBH-M-MC-HTS

The HTS-BR-KBH-M-MC-HTS sub-transmission system supplies Keysborough (KBH), Mentone (M), Mordialloc (MC) and Beaumaris (BR) zone substations as shown below.

Figure 98 - HTS-BR-KBH-M-MC-HTS sub-transmission system

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The Keysborough (KBH) zone substation was commissioned in 2014-15. As part of this project, a second HTS-M 66 kV line has been established using the previous out-of-service HTS-CRM No.1 66 kV line. In addition, the exiting 66 kV droppers at BR zone substation have been replaced to reinforce this system.

After the new zone substation was commissioned, some load has been transferred from Dandenong South (DSH), Mordialloc (MC) and Noble Park (NP) onto the new KBH zone

Strategy



substation. This transfer is expected to increase the demand on this sub-transmission system loop as reflected in the figure below.

The critical limitation on this sub-transmission system is the HTS-M No.2 66 kV line for an outage of the HTS-M No.1 66 kV line during maximum demand conditions. Similarly, for an outage of the HTS-BR 66 kV line, the KBH-M-MC 66 kV line would become overloaded (and vice versa).


HTS-BR-KBH-M-MC-HTS is a summer-critical sub-transmission system. The actual maximum demand on this system for summer 2015-16 was 1,195 Amps which occurred on 23 February 2016 at approximately 4:20 pm.


Figure 99 – Forecast maximum demand against HTS-BR-KBH-M-MC-HTS system ratings

The figure above shows that the actual maximum demand on the HTS-BR-KBH-M-MC-HTS sub-transmission system has been above its summer (N-1) rating in 2012-13 and 2013-14. Given a flat demand growth forecast over the next five years, there would not be a significant amount of incremental energy-at-risk if critical sections of this system are out-of-service during maximum demand conditions.

The bar chart below depicts the expected unserved energy for the HTS-BR-KBH-M-MC-HTS sub-transmission system following the loss of HTS-BR line of this system for the 10% PoE maximum demand forecast and the hours per year that the 10% PoE maximum demand forecast is expected

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to exceed the system’s summer (N-1) rating. The line graph shows the expected value of unserved energy in each year, for the 10% PoE summer maximum demand forecast.


As shown above, if there is a forced outage of critical sections of this system during summer maximum demand conditions, there will be insufficient capacity in this sub-transmission system to supply all demand in 2016-17 for about 12 hours.

It is emphasised that the probability of a major sub-transmission line outage occurring during summer maximum demand periods is very low. When the energy-at-risk is weighted by this low probability, the expected unserved energy is estimated to be 28 kWh in 2016-17. If no action is taken, this figure is expected to rise to 54 kWh in 2020-21, with the expected value of unserved energy of around $2,172 (based on a VCR of $40,550 per MWh).



1. Maintain contingency plan to transfer load to adjacent sub-transmission systems and the use of dynamic line ratings.

a. Plans to transfer load to adjacent sub-transmission systems via the distribution feeder network are established. These plans are reviewed annually prior to the summer season. Transfer capability away from this system is assessed at 59.7 MVA for summer 2016-17.

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2. Upgrade HTS-M No.2 66 kV line.

3. Upgrade KBH-M-MC 66 kV line.


The risk assessment shows that the expected value of unserved energy is insufficient to justify augmentation within the next five years. Until a longer-term solution is implemented, UE proposes to maintain contingency plans that include the use of dynamic line ratings and load transfers to adjacent sub-transmission systems for an unplanned outage of critical sections of this system under critical loading conditions.


HTS-BR-KBH-M-MC-HTS system summary

HTS-KBH-M/MC-BR-HTS system




HTS-KBH-M/MC-BR-HTS system 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.95 0.95 0.95 0.95 0.95






Expected unserved energy at 10% PoE demand ($) 1,154 1,452 1,435 1,984 2,172

Strategy



HTS-MR-BT-NB-HTS

The HTS-MR-BT-NB-HTS 66kV sub-transmission system supplies Moorabbin (MR), Bentleigh (BT) and North Brighton (NB) zone substations in a looped arrangement.

This system was upgraded in December 2011 when the primary legs of this system were reconductored (HTS-MR 66 kV line and HTS-NB 66 kV line) to achieve a summer cyclic rating of 1,120 Amps. This system was again upgraded in 2014 when the NB-BT 66 kV line was up-rated. This is reflected in the figure below.

The critical limitation on this sub-transmission system is currently the BT-MR 66 kV line for an outage of the HTS-NB 66 kV line during maximum demand conditions. Similarly, for an outage of the HTS-MR 66 kV line, the HTS-NB 66 kV line would become overloaded.


HTS-MR-BT-NB-HTS is a summer-critical sub-transmission system. The actual maximum demand on this system for summer 2015-16 was 978 Amps which occurred on 8 March 2016 at approximately 5:50 pm.


Figure 101 – Forecast maximum demand against HTS-MR-BT-NB-HTS system ratings

The figure above shows that the actual maximum demand on the HTS-MR-BT-NB-HTS sub-transmission system was above its summer (N-1) rating in 2013-14. Given a flat demand over the

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next five years, there would not be any incremental energy-at-risk if critical sections of this system are out-of-service during maximum demand conditions.

The bar chart below depicts the expected unserved energy for the HTS-MR-BT-NB-HTS sub-transmission system following the loss of critical sections of this system for the 10% PoE maximum demand forecast and the hours per year that the 10% PoE maximum demand forecast is expected to exceed the system’s summer (N-1) rating. The line graph shows the expected value of unserved energy in each year, for the 10% PoE summer maximum demand forecast.



It is emphasised that the probability of a major sub-transmission line outage occurring during summer maximum demand periods is very low. When the energy-at-risk is weighted by this low probability, the expected unserved energy is estimated to be 20 kWh in 2016-17. If no action is taken, this figure is expected to rise to 23 kWh in 2020-21, with the expected value of unserved energy of around $940 (based on a VCR of $40,550 per MWh).




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Plans to transfer load to adjacent sub-transmission systems via the distribution feeder network are established. These plans are reviewed annually prior to the summer season. Transfer capability away from this system is assessed at 11.9 MVA for summer 2016-17.

2. Thermally up-rate approximately 1.3 km of the BT-MR 66 kV line by 2019-20 at an approximate cost of $275k.


The risk assessment shows that the expected value of unserved energy is insufficient to justify augmentation within the next five years. Until a longer-term solution is implemented, UE proposes to maintain contingency plans that include the use of dynamic line ratings and load transfers to adjacent sub-transmission systems for an unplanned outage of critical sections of this system under critical loading conditions.


HTS-MR-BT-NB-HTS system summary

HTS-MR-BT-NB-HTS system




HTS-MR-BT-NB-HTS system 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.95 0.95 0.95 0.95 0.95







Strategy



HTS-HT-CM-SR-HTS

The HTS-HT-CM-SR-HTS 66kV sub-transmission system supplies Heatherton (HT), Cheltenham (CM) and Sandringham (SR) zone substations in a looped arrangement.

The critical section on this sub-transmission system is currently the HTS-HT 66 kV line for an outage of the HTS-SR 66 kV line during maximum demand conditions. Similarly, for an outage of the HTS-HT 66 kV line, the HTS-SR 66 kV line would become overloaded.


HTS-HT-CM-SR-HTS is a summer-critical sub-transmission system. The actual maximum demand on this system for summer 2015-16 was 905 Amps which occurred on 23 February 2016 at approximately 4:08 pm.


Figure 103 – Forecast maximum demand against the HTS-SR-CM-HT-HTS system ratings

The figure above shows that the maximum demand on the HTS-HT-CM-SR-HTS sub-transmission system is expected to remain below its summer (N-1) rating over the next five years.


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HTS-HT-CM-SR-HTS system summary

HTS-SR-CM-HT-HTS system




HTS-SR-CM-HT-HTS system 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.95 0.95 0.95 0.95 0.95







Strategy



6.9.2.4 MTS sub-transmission systems

There are currently two UE 66 kV sub-transmission systems connected to Malvern Terminal Station (MTS). These systems are:

1. MTS-CFD-EL-EM-MTS

2. MTS-OAK-OR-MTS

There are currently six UE 22 kV radial feeders exiting MTS. These feeders supply Burwood (BH) and Surrey Hills (SH) zone substations and traction load to Ashburton, Caulfield, East Malvern and Gardiner railway substations.

MTS-CFD-EL-EM-MTS

The MTS-CFD-EL-EM-MTS sub-transmission system supplies Caulfield (CFD), Elsternwick (EL) and East Malvern (EM) zone substations as shown below.

Figure 104 – MTS-CFD-EL-EM-MTS sub-transmission system

MTS

CFD

EM

EL

In 2007, CFD zone substation was inserted into this sub-transmission system. This system previously supplied Elsternwick (EL) and East Malvern (EM) zone substations.

In 2012, a 66 kV line between MTS and the EL-EM leg of the loop was commissioned to form a tee connection. This new line forms the third primary leg of the system.

Strategy



The critical section on this sub-transmission system is currently the MTS-CFD 66 kV lines for an outage of the MTS-EM/EL 66 kV line during maximum demand conditions. Similarly, for an outage of the MTS-CFD 66 kV line, the MTS-EM/EL 66 kV line would become overloaded.


MTS-CFD-EL-EM-MTS is a summer-critical sub-transmission system. The actual maximum demand on this system for summer 2015-16 was 859 Amps which occurred on 19 December 2016 at approximately 5:18 pm.


Figure 105 – Forecast maximum demand against MTS-CFD-EL-EM-MTS system ratings

The figure above shows that the maximum demand on the MTS-CFD-EL-EM-MTS sub-transmission system is expected to remain within its summer (N-1) rating over the next five years.


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MTS-CFD-EL-EM-MTS system summary

MTS-CFD-EL-EM-MTS system




MTS-CFD-EL-EM-MTS system 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.95 0.95 0.95 0.95 0.95







Strategy



MTS-OAK-OR-MTS

The MTS-OAK-OR-MTS 66kV sub-transmission system supplies Oakleigh (OAK) and Ormond (OR) zone substations in a looped arrangement.

The critical limitation on this sub-transmission system is currently the MTS-OR 66 kV lines for an outage of the MTS-OAK 66 kV line during maximum demand conditions. Similarly, for an outage of the MTS-OR 66 kV line, the MTS-OAK 66 kV line would become overloaded.


MTS-OAK-OR-MTS is a summer-critical sub-transmission system. The actual maximum demand on this system for summer 2015-16 was 588 Amps which occurred on 13 January 2016 at approximately 5:26 pm.


Figure 106 – Forecast maximum demand against MTS-OAK-OR-MTS system ratings

The figure above shows that the maximum demand on the MTS-OAK-OR-MTS sub-transmission system is expected to remain within its summer (N-1) rating over the next five years.


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MTS-OAK-OR-MTS system summary

MTS-OR-OAK-MTS system




MTS-OR-OAK-MTS system 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.95 0.95 0.95 0.95 0.95






Expected unserved energy at 10% PoE demand ($) 0.0 0.0 0.0 0.0 0.0

Strategy



MTS-SH-MTS

Surrey Hills (SH) zone substation is supplied via two 22 kV radial feeders from MTS, one of which is shared with Burwood (BW) zone substation.

In the absence of additional load being transferred to this sub-transmission system, it will not be necessary to undertake any demand related works within this planning period.


MTS-SH-MTS is a summer-critical sub-transmission system. The actual maximum demand on this system for summer 2015-16 was 172 Amps which occurred on 19 December 2015 at approximately 5:29 pm.


Figure 107 – Forecast maximum demand against MTS-SH-MTS system ratings

The figure above shows that the maximum demand on the MTS-SH-MTS sub-transmission system is expected to remain within its summer (N-1) rating over the next five years.


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MTS-SH-MTS system summary

MTS-SH-MTS system




MTS-SH-MTS system 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.95 0.95 0.95 0.95 0.95







Strategy



MTS-BW-MTS

Burwood (BW) zone substation is supplied via three 22 kV radial feeders from MTS, one of which is shared with Surrey Hills (SH) zone substation.


MTS-BW-MTS is a summer-critical sub-transmission system. The actual maximum demand on this system for summer 2015-16 was 472 Amps which occurred on 8 March 2016 at approximately 6:35 pm.


Figure 108 – Forecast maximum demand against MTS-BW-MTS system ratings

The figure above shows that the maximum demand on the MTS-BW-MTS sub-transmission system is expected to remain within its summer (N-1) rating over the next five years.


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MTS-BW-MTS system summary

MTS-BW-MTS system




MTS-BW-MTS system 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.95 0.95 0.95 0.95 0.95







Strategy



6.9.2.5 RTS sub-transmission systems

There are currently two 66 kV sub-transmission systems connected to Richmond Terminal Station (RTS) that supply two UE zone substations. The systems are:

1. RTS-EW-SK-RTS

2. RTS-CL-K-RTS

RTS-EW-SK-RTS

The RTS-EW-SK-RTS 66 kV sub-transmission system is a looped system shared between UE and CitiPower that supplies UE’s Elwood (EW) zone substation as well as CitiPower’s St Kilda (SK) zone substation. Planning on this system is therefore a joint responsibility.

AusNet Transmission Group has commenced an asset replacement project at RTS to replace the ageing transformers and other plants. As part of this project, some works associated with the RTS-EW 66 kV sub-transmission line will be required by 2016-17.

The ownership of the 66 kV assets supplying EW and SK zone substations are listed in the table below.


66kV Line Ownership

RTS-EW Distribution asset owned by UE

RTS-SK Distribution asset owned by CitiPower

EW-SK Distribution asset owned by UE

Embedded generation in the area helps to reduce demand at SK zone substation.

The critical limitation on this sub-transmission system is currently the RTS-EW 66 kV line for an outage of the RTS-SK 66 kV line during maximum demand conditions. Similarly, for an outage of the RTS-EW 66 kV line, the RTS-SK 66 kV line would become overloaded.


RTS-EW-SK-RTS is a summer-critical sub-transmission system. The actual maximum demand on this system for summer 2015-16 was 530 Amps which occurred on 13 January 2016 at approximately 5:08 pm.


Strategy



Figure 109 – Forecast maximum demand against RTS-EW-SK-MTS system ratings

The figure above shows that with the embedded generation scheme in service, the maximum demand on the RTS-EW-SK-RTS sub-transmission system does not exceed its summer (N-1) rating over the next five year period. However, in the absence of the embedded generation scheme, the maximum demand on the system is expected to exceed its summer (N-1) rating from 2020-21.

The bar chart below depicts the expected unserved energy for the RTS-EW-SK-RTS sub-transmission system following the loss of critical sections of this system for the 10% PoE maximum demand forecast and the hours per year that the 10% PoE maximum demand forecast is expected to exceed the system’s summer (N-1) rating. The line graph shows the expected value of unserved energy in each year, for the 10% PoE summer maximum demand forecast.

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Forecast Load with Generation Forecast Load without Generation

Summer (N-1) rating Summer (N) rating

Strategy



Figure 110 –Annual hours at risk, expected unserved energy and expected value of unserved energy

As shown above, if there is a forced outage of critical sections of this sub-transmission system during summer maximum demand conditions, there will be insufficient capacity in this sub-transmission system to supply all demand in 2020-21 for about 1 hour, assuming the embedded generation scheme is in service.

It is emphasised that the probability of a major sub-transmission line outage occurring during summer maximum demand periods is very low. In the absence of the embedded generation scheme during maximum demand periods, when the energy-at-risk is weighted by this low probability, the expected unserved energy is estimated to be 0.3 kWh in 2020-21 with the expected value of unserved energy of around $12 (based on a VCR of $40,550 per MWh).




Plans to transfer load to adjacent sub-transmission systems via the distribution feeder network are established by UE and CitiPower. These plans are reviewed annually prior to the summer season. Transfer capability away from EW and SK zone substations is assessed at 4.6 MVA and 5.0 MVA respectively for summer 2016-17.

2. Upgrade the RTS-EW line.

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Upgrade the RTS-EW 66 kV line droppers at EW zone substation by 2024-25 at an estimated cost of $85k.


The risk assessment shows that the expected value of unserved energy is insufficient to justify augmentation within the next five years. Until a longer-term solution is implemented, UE and CitiPower proposes to maintain contingency plans to transfer load quickly to adjacent sub-transmission systems for an unplanned outage of critical section of this sub-transmission system under critical loading conditions.


Strategy



RTS-EW-SK-RTS system summary

RTS-EW-SK-RTS system




RTS-EW-SK-RTS system (With Generation) 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.95 0.95 0.95 0.95 0.95







RTS-EW-SK-RTS system (Without Generation) 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.95 0.95 0.95 0.95 0.95







Strategy



RTS-CL-K-RTS

The RTS-CL-K-RTS 66 kV sub-transmission system is a looped system shared between UE and CitiPower that supplies UE’s Gardiner (K) zone substation as well as CitiPower’s Camberwell (CL) zone substation. Planning on this system is therefore a joint responsibility.

The ownership of the 66 kV assets supplying K and CL zone substations are listed in the table below.


66kV Line Ownership

RTS-K Distribution asset owned by UE

RTS-CL Distribution asset owned by CitiPower

CL-K Distribution asset owned by CitiPower

This system was upgraded in 2014 when sections of the RTS-K 66 kV line were up-rated. This system is now limited by the station assets at RTS. AusNet Transmission Group has commenced an asset replacement project at RTS to replace the ageing transformers and other plants by 2017-18. As part of this project, AusNet Transmission Group plans to upgrade these assets as part of the RTS re-development project which is expected to be completed by 2016-17.

The critical limitation on the sub-transmission system is currently the RTS-K 66 kV line owned and operated by UE for an outage of the RTS-CL 66 kV line during maximum demand conditions.


RTS-CL-K-RTS is a summer-critical sub-transmission system. The actual maximum demand on this system for summer 2015-16 was 902 Amps which occurred on 18 December 2015 at approximately 3:57 pm.


Strategy



Figure 111 - Forecast maximum demand against RTS-CL-K-RTS system ratings

The figure above shows that except for 2014-15, the actual maximum demand on the RTS-CL-K-RTS sub-transmission system has been above its summer (N-1) rating since 2010-11. Given a steady demand growth over the next five years, there would be significant amount of energy-at-risk should the RTS-CL 66 kV line outage occurs during maximum demand conditions.

The bar chart below depicts the expected unserved energy with the RTS-CL 66 kV line out-of-service for the 10% PoE maximum demand forecast and the hours per year that the 10% PoE maximum demand forecast is expected to exceed the system’s summer (N-1) rating. The line graph shows the expected value of unserved energy in each year, for the 10% PoE summer maximum demand forecast.

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As shown above, if there is a forced outage of the RTS-CL 66 kV line during summer maximum demand conditions, there will be insufficient capacity in this sub-transmission system to supply all demand in 2016-17 for about 228 hours.





Plans to transfer load to adjacent sub-transmission systems via the distribution feeder network are established by UE and CitiPower. These plans are reviewed annually prior to the summer season. Transfer capability away from K and CL zone substations is assessed at 4.3 MVA and 10.0 MVA respectively for summer 2016-17.

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The risk assessment shows that the expected value of unserved energy is insufficient to justify augmentation within the next five years. Until a longer-term solution is implemented, UE and CitiPower proposes to maintain contingency plans to transfer load quickly to adjacent sub-transmission systems for an unplanned outage of critical section of this sub-transmission system under critical loading conditions.


RTS-CL-K-RTS system summary

RTS-K-CL-RTS system




RTS-K-CL-RTS system 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.95 0.95 0.95 0.95 0.95



N-1 energy at risk at 10% PoE demand (MWh) 2,952 3,158 2,335 3,093 4,112




Strategy



6.9.2.6 RWTS sub-transmission system

There is currently one UE 66 kV sub-transmission system connected to Ringwood Terminal Station (RWTS) that supplies two UE zone substations. The system is:

1. RWTS-BH-NW-RWTS

UE and AusNet Electricity Services also own a number of distribution feeders at RWTS 22 kV.

RWTS-BH-NW-RWTS

The RWTS-BH-NW-RWTS 66 kV sub-transmission system supplies Box Hill (BH) and Nunawading (NW) zone substations in a loop arrangement. This system was upgraded in December 2011.

The critical limitation on the sub-transmission system is currently the RWTS-BH 66 kV line for an outage of the RWTS-NW 66 kV line during maximum demand conditions. Similarly, for an outage of the RTS-BH 66 kV line, the RTS-NW 66 kV line would become overloaded.


RWTS-BH-NW-RWTS is a summer-critical sub-transmission system. The actual maximum demand on this system for summer 2015-16 was 943 Amps which occurred on 18 December 2015 at approximately 4:42 pm.


Strategy



Figure 113 – Forecast maximum demand against RWTS-BH-NW-RWTS system ratings

The figure above shows that the maximum demand on the RWTS-BH-NW-RWTS sub-transmission system is not expected to exceed its summer (N-1) rating over the next five year period.


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RWTS-BH-NW-RWTS system summary

RWTS-BH-NW-RWTS system




RWTS-BH-NW-RWTS system 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.95 0.95 0.95 0.95 0.95







Strategy



6.9.2.7 SVTS sub-transmission systems

There are five 66 kV sub-transmission systems exiting Springvale Terminal Station (SVTS) that supply nine UE zone substations and one CitiPower zone substation. These systems are:

1. SVTS-EB-RD-SVTS

2. SVTS-GW-NO-SVTS

3. SVTS-NP-SS-SVTS

4. SVTS-CDA-OE-SVTS

5. SVTS-SV-SVW-SVTS

SVTS-EB-RD-SVTS

The SVTS-EB-RD-SVTS sub-transmission system is a looped system shared between UE and CitiPower that supplies UE’s East Burwood (EB) zone substation and Riversdale (RD) zone substation owned by CitiPower. Planning on this system is therefore a joint responsibility.

The ownership of the 66 kV assets supplying EB and RD zone substations are listed in the table below.


66kV Line Ownership

SVTS-EB Distribution asset owned by UE

SVTS-RD Distribution asset owned by CitiPower

EB-RD Distribution asset owned by UE

In previous planning documents, the critical limitation on this sub-transmission system was identified as the SVTS-RD 66 kV line. Accordingly, both UE and CitiPower undertook joint planning and evaluated a number of alternatives that included:

Up-rating the SVTS-RD 66 kV line at an estimated cost of $3.9 million.

Up-rating the SVTS-EB 66 kV line by 2017-18 at an estimated cost of $0.53 million.

Transferring RD zone substation from SVTS to MTS to create the SVTS-EB-SVTS and MTS-RD-BW-MTS systems. This option involved converting BW zone substation from 22 kV to 66 kV. The cost of the sub-transmission portion of the works was estimated to be $8 million.

UE and CitiPower determined that the most efficient and prudent investment strategy was to up-rate the SVTS-RD 66 kV line. This project was completed by CitiPower in 2014-15. The increase in the system rating is reflected in the figure below.

The critical limitation on the sub-transmission system at the completion of the upgrade will be the SVTS-EB 66 kV line for an outage of the SVTS-RD 66 kV line during maximum demand

Strategy



conditions. Similarly, for an outage of the SVTS-EB 66 kV line, the EB-RD 66 kV line would become overloaded.


SVTS-EB-RD-SVTS is a summer-critical sub-transmission system. The actual maximum demand on this system for summer 2015-16 was 834 Amps which occurred on 13 January 2016 at approximately 6:00 pm.


Figure 114 – Forecast maximum demand against SVTS-EB-RD-SVTS system ratings

The figure above shows that with the exception of 2014-15, the actual maximum demand on the SVTS-EB-RD-SVTS sub-transmission system has been above its summer (N-1) rating. Given a steady demand growth over the next five years, there would be significant amount of energy-at-risk if critical sections of this system are out-of-service during maximum demand conditions.

The bar chart below depicts the expected unserved energy for the SVTS-EB-RD-SVTS sub-transmission system following the loss of critical sections of this system for the 10% PoE maximum demand forecast and the hours per year that the 10% PoE maximum demand forecast is expected to exceed the system’s summer (N-1) rating. The line graph shows the expected value of unserved energy in each year, for the 10% PoE summer maximum demand forecast.

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It is emphasised that the probability of a major sub-transmission line outage occurring during summer maximum demand periods is very low. When the energy-at-risk is weighted by this low probability, the expected unserved energy is estimated to be 338 kWh in 2016-17. If no action is taken, this figure is expected to rise to 1,236 kWh in 2020-21, with the expected value of unserved energy of around $50,115 (based on a VCR of $40,550 per MWh).




Plans to transfer load to adjacent sub-transmission systems via the distribution feeder network are established by UE and CitiPower. CitiPower has in place a plant overload protection scheme (POPS) at RD zone substation. This scheme can be placed in service at times of emergency in order to reduce the system loading. These plans are reviewed annually prior to the summer season. Transfer capability away EB and RD zone substations are assessed at 20.3 MVA and 3.0 MVA for summer 2016-17.

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2. Upgrade the SVTS-EB 66 kV line.

Reconductor approximately 750 metres of the SVTS-EB 66 kV line at an estimated cost of $530k.


Based on the current maximum demand forecast, UE intends to upgrade the SVTS-EB 66 kV line before summer 2017-18. The estimated cost of this augmentation is $530k. In the absence of any lower-cost options, this is the most likely least cost technically feasible network option.

Until a longer-term solution is implemented, UE proposes to maintain contingency plans to transfer load quickly to adjacent sub-transmission systems for an unplanned outage of the critical sections of this sub-transmission system under critical loading conditions.


Embedded generation or demand management methodologies to reduce the magnitude of maximum demand within the areas presently supplied by EB / RD zone substations could defer or avoid the proposed network augmentation.


Figure 116 – SVTS-EB-RD-SVTS system load profile on maximum demand day (2013-14)

In order to defer the proposed augmentation by twelve months, a non-network solution would need to reduce the summer maximum demand at EB / RD zone substations, between the hours of 15:00

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SVTS-EB-RD-SVTS System - Load profile 16 January 2014

Strategy



to 20:00 on maximum demand days, by approximately 4.0 MVA. This amount of load reduction would need to be implemented by summer 2017-18 and be suitably located in the area that is presently supplied by EB / RD zone substations.

The estimated total annual cost of the preferred network option is $33,760. This provides a broad upper bound indication of the maximum contribution from UE which may be available to non-network service providers for deferring or avoiding the need to upgrade the SVTS-EB 66 kV line.

Next steps

UE intends to implement the preferred network solution in the absence of any commitment from interested parties to offer network support services by installing local generation or through demand management initiatives that would reduce the summer maximum demand at EB / RD zone substations.

UE therefore invites interested parties to submit their proposal or to engage in joint planning with UE to defer or avoid the proposed network augmentation.

SVTS-EB-RD-SVTS system summary

SVTS-EB-RD-SVTS system

Summer cyclic ‘N’ Rating (MVA) 169.8

Summer cyclic ‘N-1’ Rating (MVA) 116.6


SVTS-EB-RD-SVTS system 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.95 0.95 0.95 0.95 0.95



N-1 energy at risk at 10% PoE demand (MWh) 418 669 949 1,199 1,529


N-1 expected energy at risk at 10% PoE demand (kWh) 338 540 767 969 1,236


Strategy



SVTS-GW-NO-SVTS

The SVTS-GW-NO-SVTS 66 kV sub-transmission system supplies Glen Waverley (GW) and Notting Hill (NO) zone substations in a looped arrangement.


SVTS-GW-NO-SVTS is a summer-critical sub-transmission system. The actual maximum demand on this system for summer 2015-16 was 911 Amps which occurred on 23 February 2016 at approximately 4:13 pm.


Figure 117 – Forecast maximum demand against SVTS-GW-NO-SVTS system ratings

The figure above shows that the maximum demand on the SVTS-GW-NO-SVTS sub-transmission system is expected to marginally exceed its summer (N-1) rating from 2018-19. However, the expected unserved energy is insignificant over the next five years.


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SVTS-GW-NO-SVTS system summary

SVTS-GW-NO-SVTS system




SVTS-GW-NO-SVTS system 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.95 0.95 0.95 0.95 0.95







Strategy



SVTS-NP-SS-SVTS

The SVTS-NP-SS-SVTS 66 kV sub-transmission system supplies Noble Park (NP) and Springvale South (SS) zone substations in a looped arrangement.

Two embedded generation schemes in the area help to reduce demand at SS on weekdays between 7:00 am and 11:00 pm. UE does not currently have network support agreements with these generators.

UE has commission the new Keysborough (KBH) zone substation in 2014. After commissioning, some load was transferred away from NP to the new KBH zone substation. This transfer is expected to reduce the demand on this system as reflected in the figure below.


SVTS-NP-SS-SVTS is a summer-critical sub-transmission system. The actual maximum demand on this system for summer 2015-16 was 817 Amps which occurred on 13 January 2016 at approximately 5:24 pm.


Figure 118 – Forecast maximum demand against SVTS-NP-SS-SVTS system ratings

The figure above shows that with the embedded generation schemes in service, the maximum demand on the SVTS-NP-SS-SVTS sub-transmission system is expected to remain within its summer (N-1) rating over the next five years. Without the embedded generation schemes, the

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Actual Load with Generation Summer (N-1) rating

Forecast Load with Generation Actual Load without Generation

Summer (N) rating Forecast Load without Generation

Strategy



maximum demand on the system is expected to marginally exceed above its summer (N-1) rating over the next two summers only.


SVTS-NP-SS-SVTS system summary

SVTS-NP-SS-SVTS system




SVTS-NP-SS-SVTS system (With Generation) 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.95 0.95 0.95 0.95 0.95







SVTS-NP-SS-SVTS system (Without Generation) 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.95 0.95 0.95 0.95 0.95







Strategy



SVTS-CDA-OE-SVTS

The SVTS-CDA-OE-SVTS 66 kV sub-transmission system supplies Oakleigh East (OE) and Clarinda (CDA) zone substations in a looped arrangement.

In 2012, the relocatable transformer (hot spare) was relocated from Dandenong Valley (DVY) zone substation to CDA zone substation. As a result, additional load was transferred onto this system as reflected in the figure below.


SVTS-CDA-OE-SVTS is a summer-critical sub-transmission system. The actual maximum demand on this system for summer 2015-16 was 417 Amps which occurred on 13 January 2016 at approximately 5:26 pm.


Figure 119 – Forecast maximum demand against SVTS-CDA-OE-SVTS system ratings

The figure above shows that the maximum demand on the SVTS-CDA-OE-SVTS sub-transmission system is expected to remain within its summer (N-1) rating over the next five years.


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SVTS-CDA-OE-SVTS system summary

SVTS-OE-CDA-SVTS system




SVTS-OE-CDA-SVTS system 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.95 0.95 0.95 0.95 0.95


Load transfer capability (MVA) 26





Strategy



SVTS-SV-SVW-SVTS

The SVTS-SV-SVW-SVTS 66 kV sub-transmission system supplies Springvale (SV) and Springvale West (SVW) zone substations in a looped arrangement.

In September 2014, UE installed series line reactors on the SVTS-SV 66 kV line to limit the fault current within allowable limits at SV and SVW zone substations. This has increased the system’s operational summer (N) rating as the loading on the SVTS-SV 66 kV line and the SVTS-SVW 66 kV line are shared equally. This is reflected in the figure below.

The critical limitation on this sub-transmission system is currently the SVTS-SV 66 kV line for an outage of the SVTS-SVW 66 kV line during maximum demand conditions. Similarly, for an outage of the SVTS-SV 66 kV line, the SVTS-SVW 66 kV line would become overloaded.


SVTS-SV-SVW-SVTS is a summer-critical sub-transmission system. The actual maximum demand on this system for summer 2015-16 was 894 Amps which occurred on 8 March 2016 at approximately 3:50 pm.


Figure 120 – Forecast maximum demand against SVTS-SV-SVW-SVTS system ratings

The figure above shows that the maximum demand on the SVTS-SV-SVW-SVTS sub-transmission system is expected to remain below its summer (N-1) rating over the next five years.

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SVTS-SV-SVW-SVTS system summary

SVTS-SV-SVW-SVTS system




SVTS-SV-SVW-SVTS system 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.95 0.95 0.95 0.95 0.95







Strategy



6.9.2.8 TBTS sub-transmission systems

There are currently two 66 kV sub-transmission systems connected to Tyabb Terminal Station (TBTS) that supply six UE zone substations. These systems are:

1. TBTS-HGS-TBTS

2. TBTS-DMA-FSH-MTN-TBTS

Rosebud (RBD) and Sorrento (STO) zone substations are connected to DMA through a ring bus and are presently supplied through the TBTS-DMA 66 kV line and the MTN-DMA 66 kV line.

TBTS-HGS-TBTS

The TBTS-HGS-TBTS 66kV sub-transmission system supplies the Hastings (HGS) zone substation in a looped arrangement.

The critical limitation on this sub-transmission system is currently the TBTS-HGS No.1 66 kV line for an outage of the TBTS-HGS No.2 66 kV line during maximum demand conditions. Similarly, for an outage of the TBTS-HGS No.1 66 kV line, the TBTS-HGS No.2 66 kV line would become overloaded.


TBTS-HGS-TBTS is a summer-critical sub-transmission system. The actual maximum demand on this system for summer 2015-16 was 419 Amps which occurred on 13 January 2016 at approximately 5:43 pm.


Strategy



Figure 121 – Forecast maximum demand against TBTS-HGS-TBTS system ratings

The figure above shows that the maximum demand on the TBTS-HGS-TBTS sub-transmission system is expected to remain within its summer (N-1) rating over the next five years.

In order to alleviate the capacity and voltage collapse conditions in the lower Mornington Peninsula, UE plans to establish a new HGS-RBD 66 kV line. As part of this project, the existing TBTS-HGS 66 kV lines are likely to require upgrading at this time due to the additional load imposed on this system.

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TBTS-HGS-TBTS system summary

The table below summarises information relating to the TBTS-HGS-TBTS system.

TBTS-HGS-TBTS system




TBTS-HGS-TBTS system 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.95 0.95 0.95 0.95 0.95







Strategy



TBTS-DMA-FSH-MTN-TBTS

Prior to 2014, TBTS-FSH-MTN-TBTS and TBTS-DMA-TBTS were two independent sub-transmission systems. In order to optimise the sub-transmission capacity utilisation in the Mornington Peninsula, UE combined the two systems together to form the new TBTS-DMA-FSH-MTN-TBTS sub-transmission system. Although this development improves the utilisation of the sub-transmission assets in the Mornington Peninsula, it does not fully alleviate the capacity limitation and voltage collapse limitation (described below).

Rosebud (RBD) and Sorrento (STO) zone substations are connected to DMA as a secondary system and are presently supplied through the TBTS-DMA-MTN sub-transmission system as shown below.

Figure 122 - TBTS-DMA-FSH-MTN-TBTS sub-transmission system

TBTS

RBD

FSH

DMA

MTN

STO

Given the multiple 66 kV supply routes and voltage limitations in this system, the risk assessment for this system is more complicated compared with other sub-transmission systems. Therefore, load flow results are used to undertake the risk assessment.

Strategy



Thermal overload

TBTS-DMA-FSH-MTN-TBTS

The TBTS-DMA-FSH-MTN-TBTS 66 kV sub-transmission system supplies Frankston South (FSH), Mornington (MTN), Dromana (DMA), Rosebud (RBD) and Sorrento (STO) zone substations.

The critical limitation on this sub-transmission system is currently the TBTS-MTN No.1 66 kV line for an outage of the TBTS-DMA 66 kV line during high demand periods. Similarly, for an outage of either the TBTS-MTN No.2 66 kV line or TBTS-FSH 66 kV line, the TBTS-MTN No.1 66 kV line would become overloaded.


TBTS-DMA-FSH-MTN-TBTS is a summer-critical sub-transmission system. The actual maximum demand on this system for summer 2015-16 was 2,139 Amps which occurred on 31 December 2015 at approximately 4:25 pm. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the sub-transmission system’s operational summer (N) and (N-1) ratings.

Figure 123 – Forecast maximum demand against TBTS-DMA-FSH-MTN-TBTS system ratings

The figure above shows that the maximum demand on the TBTS-DMA-FSH-MTN-TBTS sub-transmission system is expected to be above its summer (N-1) rating from 2016-17. Given a steady demand growth over the next five years, there would be significant amount of energy-at-risk if critical sections of this system are out-of-service during maximum demand conditions.

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Forecast Load Summer (N-1) rating Summer (N) rating Actual Load

Strategy



TBTS-DMA-MTN

This is a subset of the main TBTS-DMA-FSH-MTN-TBTS sub-transmission system. The TBTS-DMA-MTN 66 kV sub-transmission system supplies Dromana (DMA), Rosebud (RBD) and Sorrento (STO) zone substations via the TBTS-DMA 66 kV line and the MTN-DMA 66 kV line.

The critical limitation on this sub-transmission system is currently the TBTS-DMA 66 kV line for an outage of the MTN-DMA 66 kV line during maximum demand periods (or vice versa).


TBTS-DMA-MTN is a summer-critical sub-transmission system. The actual maximum demand on this system for summer 2015-16 was 1,155 Amps which occurred on 31 December 2015 at approximately 4:27 pm.


Figure 124 – Forecast maximum demand against TBTS-DMA-MTN system ratings

The figure above shows that the maximum demand on the TBTS-DMA-MTN sub-transmission system is expected to be above its summer (N-1) rating from 2016-17. Given a steady demand growth over the next five years, there would be significant amount of energy-at-risk if critical sections of this system are out-of-service during maximum demand conditions.

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DMA-RBD-DMA

The DMA-RBD-DMA 66kV sub-transmission system supplies Rosebud (RBD) and Sorrento (STO) zone substations in a looped arrangement with RBD only.

The critical limitation on this sub-transmission system is currently the DMA-RBD No.1 66 kV line for an outage of the DMA-RBD No.2 66 kV line during maximum demand periods (and vice versa).

Magnitude, Probability and Impact of Loss of Load

DMA-RBD-DMA is a summer-critical sub-transmission system. The actual maximum demand on this system for summer 2015-16 was 784 Amps which occurred on 31 December 2015 at approximately 4:25 pm.


Figure 125 – Forecast maximum demand against DMA-RBD-DMA system ratings

The figure above shows that the actual maximum demand on the DMA-RBD-DMA sub-transmission system has been above its summer (N-1) rating since 2011-12. Given a steady demand growth over the next five years, there would be significant amount of energy-at-risk if critical sections of this system are out-of-service during maximum demand conditions.

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RBD-STO-RBD

The RBD-STO-RBD 66kV sub-transmission system supplies the Sorrento (STO) zone substation via two radial lines.

The critical limitation on this sub-transmission system is currently the RBD-STO No.1 66 kV line for an outage of the RBD-STO No.2 66 kV line during maximum demand periods (and vice versa).


RBD-STO-RBD is a summer-critical sub-transmission system. The actual maximum demand on this system for summer 2015-16 was 400 Amps which occurred on 31 December 2015 at approximately 4:25 pm.


Figure 126 – Forecast maximum demand against RBD-STO-RBD system ratings

The figure above shows that the maximum demand on the RBD-STO-RBD sub-transmission system is expected to remain within its summer (N-1) rating over the next five years.

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Voltage collapse

UE has also identified a risk of voltage collapse in the lower part of the Mornington Peninsula should a forced outage of either the MTN-DMA 66 kV line or the TBTS-DMA 66 kV line occur during maximum demand periods, with the former being the more severe condition. Given the relatively long sub-transmission lines extending to STO from TBTS (approximately 59 km), the voltage collapse limitation is considered to be prominent over the thermal capacity limitation. UE has installed capacitor banks at STO and RBD zone substations to provide reactive power compensation for the load. Although DMA zone substation is not equipped with any capacitor banks, the station also operates near unity power factor due to the use of pole-mounted capacitor banks within the 22 kV distribution network. The effectiveness of these devices together with the on-load tap changers (of zone substation transformers) to maintain voltage levels within acceptable levels is diminishing rapidly in the event of loss of one of the sub-transmission lines to DMA zone substation during maximum demand conditions because of the magnitude of the losses along the 66 kV lines.

The figure above shows that an unplanned outage of the MTN-DMA 66 kV line is expected to lead to voltage collapse in the lower Mornington Peninsula from summer 2016-17. Therefore, pre-contingent load curtailment may be required from this time to maintain regulatory compliance with respect to voltage.


The Lower Mornington Peninsula RIT-D concluded in May 2016 when the Final Project Assessment Report (FPAR) was published. The RIT-D assessment recommended a technically feasible and economic solution to mitigate the risk of supply interruption and/or to alleviate the emerging limitation in the Mornington Peninsula sub-transmission network. The preferred solution is a hybrid of GreenSync’s 4-year non network solution starting from summer 2018-19, followed by the network option i.e. to build and commission HGS-RBD 66kV line by summer 2022-23.

This solution shall:

Reduce energy at risk from summer 2018-19 till 2021-22 in the lower Mornington supply area;

Defer network augmentation by two years i.e. from 2020-21 to 2022-23;

Maximise net economic benefits for the electricity market;

Address capacity limitation on the DMA-RBD 66 kV lines;

Address capacity limitation on the MTN-DMA 66 kV line;

Address capacity limitation on the TBTS-DMA 66 kV line;

Address capacity limitation on the TBTS-MTN No.1 66 kV line; and

Address voltage collapse limitation in the lower Mornington Peninsula.

Strategy



Until this solution is implemented, UE proposes to maintain contingency plans to transfer load quickly to adjacent sub-transmission systems for an unplanned outage of critical section of this system under critical loading conditions.

Next steps

UE concluded a Regulatory Investment Test for Distribution (RIT-D) assessment for addressing the abovementioned limitations by publishing the Final Project Assessment Report (FPAR) in May 2016.

GreenSync’s four year non-network solution starting from summer 2018-19, followed by the build and commissioning of HGS-RBD 66 kV line is a committed project.

TBTS-FSH-MTN-DMA-TBTS system summary

Thermal

TBTS-FSH-MTN-DMA-TBTS system




TBTS-FSH-MTN-DMA-TBTS system 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.95 0.95 0.95 0.95 0.95



TBTS-DMA-MTN system




TBTS-DMA-MTN system 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.95 0.95 0.95 0.95 0.95



Strategy



DMA-RBD-DMA system




DMA-RBD-DMA system 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.95 0.95 0.95 0.95 0.95



RBD-STO-RBD system




RBD-STO-RBD system 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.95 0.95 0.95 0.95 0.95



Voltage

TBTS-DMA-MTN

Voltage collapse limit (MVA) 120

Embedded generator installed capacity (MVA) 1.0

DMA / RBD / STO Total Demand 2016-17 2017-18 2018-19 2019-20 2020-21

10% PoE summer maximum demand (MVA) 133 132 134 135 137

Power factor 0.99 0.99 0.99 0.99 0.99


Strategy



6.9.2.9 TSTS sub-transmission systems

There are currently two UE 66 kV sub-transmission systems supplying UE demand connected to Templestowe Terminal Station (TSTS) that supply three UE zone substations. The systems are:

1. TSTS-BU-WD-TSTS

2. TSTS-DC-TSTS

TSTS-BU-WD-TSTS

The TSTS-BU-WD-TSTS 66kV sub-transmission system supplies the Bulleen (BU) and West Doncaster (WD) zone substations in a looped arrangement.


TSTS-BU-WD-TSTS is a summer-critical sub-transmission system. The actual maximum demand on this system for summer 2015-16 was 672 Amps which occurred on 19 December 2015 at approximately 5:58 pm.


Figure 127 – Forecast maximum demand against TSTS-BU-WD-TSTS system ratings

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Strategy



The figure above shows that the maximum demand on the TSTS-BU-WD-TSTS sub-transmission system is expected to remain within its summer (N-1) rating over the next five years.


TSTS-BU-WD-TSTS system summary

TSTS-BU-WD-TSTS system




TSTS-BU-WD-TSTS system 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.95 0.95 0.95 0.95 0.95







Strategy



TSTS-DC-TSTS

The TSTS-DC-TSTS 66kV sub-transmission system supplies the Doncaster (DC) zone substation in a looped arrangement.

The critical limitation on this sub-transmission system is currently the TSTS-DC No.1 66 kV line for an outage of the TSTS-DC No.2 66 kV line during maximum demand period. Similarly, for an outage of the TSTS-DC No.1 66 kV line, the TSTS-DC No.2 66 kV line would become overloaded.


TSTS-DC-TSTS is a summer-critical sub-transmission system. The actual maximum demand on this system for summer 2015-16 was 763 Amps which occurred on 13 January 2016 at approximately 5:59 pm.


Figure 128 – Forecast maximum demand against TSTS-DC-TSTS system ratings

The figure above shows that the actual maximum demand on the TSTS-DC-TSTS sub-transmission system was above its summer (N-1) rating in 2013-14. Given a steady demand growth over the next five years, there would be significant amount of energy-at-risk if critical sections of this system are out-of-service during maximum demand conditions.

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Strategy



The bar chart below depicts the expected unserved energy for the TSTS-DC-TSTS sub-transmission system following the loss of critical sections of this system for the 10% PoE maximum demand forecast and the hours per year that the 10% PoE maximum demand forecast is expected to exceed the system’s summer (N-1) rating. The line graph shows the expected value of unserved energy in each year, for the 10% PoE summer maximum demand forecast.


As shown above, if there is a forced outage of critical sections of this system during summer maximum demand conditions, there will be insufficient capacity in this sub-transmission system to supply all demand in 2016-17 for about 3 hour.






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Strategy




2. Up-rate and re-conductor the TSTS-DC 66 kV lines.

Up-rate TSTS-DC No.1 66kV line and droppers which is strung on towers owned by AusNet Transmission Group by 2017-18. In addition, re-conductor 0.7 km of TSTS-DC No.1 66 kV line and 1.3 km of TSTS-DC No.2 66kV line by summer 2025-26.

3. Establish a new zone substation with a separate sub-transmission system.

Establishing a new 66/22 kV Templestowe (TSE) zone substation with new distribution feeders is regarded as a long-term solution to supply the growing electricity demand in this area. Templestowe is identified as a suitable locality for a new zone substation to offload DC because it allows the distribution feeders to be shortened, thereby improving distribution feeder utilisation and supply reliability in this area as well as addressing capacity limitations. Accordingly, UE purchased a site in 2012 within the Templestowe area for this zone substation. This new zone substation would be supplied via a new 66 kV sub-transmission line from TSTS to connect into the existing BU-WD 66kV line. The estimated cost of this augmentation is $19 million.

The need for the new TSE zone substation is driven by high demand growth in the areas supplied by the Bulleen, Doncaster and West Doncaster zone substations as well as addressing distribution feeder limitations in these areas. The latest maximum demand forecasts in these areas have growth revised downwards compared to last year. As a result, the installation of a 4th transformer at DC zone substation may be a more economical solution in the short term.


Based on the current maximum demand forecast, UE intends to up-rate TSTS-DC No.1 66kV line and droppers which is strung on towers owned by AusNet Transmission Group by 2017-18. The estimated cost of this augmentation is $0.2 million. In addition, re-conductor 0.7 km of TSTS-DC No.1 66 kV line and 1.3 km of TSTS-DC No.2 66kV line by summer 2025-26.

In the absence of any lower-cost options, this is the most likely least cost technically feasible network option. This augmentation shall:

Address the capacity limitations on the TSTS-DC-TSTS system;

Improve supply reliability in the area.

Until a longer-term solution is implemented, UE proposes to maintain contingency plans to transfer load quickly to adjacent zone substation for an unplanned outage of a transformer at DC zone substation under critical loading conditions.

Strategy




Embedded generation or demand management schemes to reduce the magnitude of maximum demand within the areas presently supplied by DC zone substation could defer or avoid the proposed network augmentation.


Figure 130 – TSTS-DC-TSTS system load profile on maximum demand day (2013-14)

In order to defer the proposed augmentation by twelve months, a non-network solution would need to reduce the summer maximum demand at DC zone substation, between the hours of 15:00 to 20:00 on maximum demand days, by approximately 1.0 MVA.35 This amount of load reduction would need to be implemented by summer 2017-18 and be suitably located in the area that is presently supplied by DC zone substation.

The estimated total annual cost of the preferred network option is around $12,740. This provides a broad upper bound indication of the maximum contribution from UE which may be available to non-network service providers for deferring or avoiding the need for the proposed augmentation.

Next steps

UE intends to implement the preferred network solution in the absence of any commitment from interested parties to offer network support services by installing local generation or through

35 This is an estimate only. The amount of load reduction required to defer the proposed augmentation will be finalized in a detailed

risk assessment.

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Strategy



demand management initiatives that would reduce the summer maximum demand at DC zone substation.

UE therefore invites interested parties to submit their proposal or to engage in joint planning with UE to defer or avoid the proposed network augmentation.

TSTS-DC-TSTS system summary

TSTS-DC-TSTS system




TSTS-DC-TSTS system 2016-17 2017-18 2018-19 2019-20 2020-21


Power factor 0.95 0.95 0.95 0.95 0.95






Expected unserved energy at 10% PoE demand ($) 244 579 1,023 1,451 1,993

Strategy



6.9.3 Distribution high-voltage feeders

UE’s distribution substations are supplied by 447 distribution feeders in a radial configuration with normally open points between adjacent feeders to provide transfer capability during emergency conditions. Historically, the average utilisation of distribution feeders at peak demand has been 60 percent. Utilisation factor describes the ratio of the feeder maximum demand to the summer cyclic rating (N) under normal operating conditions.

Under probabilistic planning, distribution feeders are generally loaded to greater than 85 percent utilisation before they are considered for possible augmentation as this represents a typical trigger-point at which some feeder augmentations become economic. This is because, the transfer capabilities reserved for maintaining continuous supply to our customers during emergency conditions diminishes with increased distribution feeder utilisation.

For a 10% PoE in 2016-17, no distribution feeders are expected to exceed their (N) cyclic rating under normal operating conditions. 50 distribution feeders are expected to exceed 85 percent of their N rating if summer 2016-17 is a 10% PoE summer. The following zone substations have 3 or more highly utilised distribution feeders – BU, CRM, DC, MGE, OR and SV which could limit transfer options between feeders.

For a 10% PoE in 2017-18, 1 distribution feeder is expected to exceed its (N) cyclic rating. A further 70 distribution feeders are expected to exceed 85 percent of their rating. The following zone substations have 3 or more highly utilised feeders – BT, BU, CRM, DC, GW, MGE, MR, MTN, NB, OR and SV which could limit transfer options between feeders.

For a 10% PoE in 2018-19, 5 distribution feeders are expected to exceed their (N) cyclic rating. Around 83 distribution feeders are expected to exceed 85 percent of their rating. The following zone substations have 3 or more highly utilised feeders – BT, BU, CFD, CRM, DC, FSH, GW, MGE, MR, MTN, NB, OAK, OR and SV which could limit transfer options between feeders.

The table below provides information regarding critical distribution feeder limitations where network augmentation to alleviate those limitations are likely to be economic in the next two years.

Table 25 – Distribution feeder limitations

Feeder Feeder location

Season of

maximum

demand

Utilisation (%)

2016-17

(forecast)

2017-18

(forecast)

CRM 35 Wells Rd, Chelsea / Chelsea Heights / Aspendale Gardens / Bangholme Area

Summer 89% 90%

DVY 24 Dandenong Frankston Rd, Carrum Downs / Dandenong South / Sandhurst Area

Summer 82% 95%

EL 10 Glenhuntly Rd, Elsternwick Area Summer 79% 99%

FSH 33 Mt Eliza Way, Mount Eliza / Frankston Flinders Rd, Frankston South Area

Summer 90% 91%

FTN 23 Hall Rd, Carrum Downs / Seaford / Skye Area

Summer 84% 90%

MGE 12 Jells Rd / Ferntree Gully Rd, Wheelers Hill / Scoresby Area

Summer 94% 108%

Strategy




A number of options are considered in identifying suitable mitigation measures to alleviate thermal capacity and transfer capacity issues on distribution feeders, including:

Permanent load transfers to neighbouring feeders.

Feeder reconductoring.

Thermal uprate.

Reactive power compensation.

New feeder ties or extensions.

New feeders.

Non-network alternatives.

Preferred network option for alleviation of limitations

The most appropriate option is selected based on practical feasibility and least lifecycle cost. The table below identifies the proposed preferred network solution that would be undertaken in the absence of any commitment from interested parties to offer network support services through demand side management initiatives. The table also provides the amount of load reduction that would be required to defer the proposed augmentations by one year.36

36 This is an indicative figure only. The amount of load reduction required to defer the proposed augmentations will be finalised in 2017 (via a detailed risk assessment).

Strategy



Table 26 – Proposed preferred network augmentations

Feeder limitation

Preferred network solution Timing (before summer)

CRM 35

CRM 35 feeder is highly utilised. It is proposed to extend the lightly utilised CRM 24 feeder to offload CRM 35 enabling better utilisation of assets. The estimated cost of this augmentation is $400,000.

In order to defer the proposed augmentation by twelve months, a non-network solution would need to reduce the summer maximum demand on CRM 35 feeder, between the hours of 14:00 to 20:00 on maximum demand days by approximately 0.5 MVA. This amount of load reduction would need to be implemented before summer 2018-19, and be suitably located within the Chelsea / Aspendale Gardens / Chelsea Heights / Edithvale / Bangholme area that is presently supplied by CRM 35 feeder.


The estimated annual cost of the preferred network option is around $25,500. This provides a broad upper bound indication of the maximum contribution from UE which may be available to non-network service providers for deferring the proposed augmentation by twelve months.

2018-19

DVY 24

DVY 24 is a highly utilised feeder. It is proposed to build a new feeder DVY 12 from the DVY zone substation to offload this feeder. The estimated cost of this augmentation is $900,000.

In order to defer the proposed augmentation by twelve months, a non-network solution would need to reduce the summer maximum demand on DVY 24 feeder, between the hours of 13:00 to 19:00 on maximum demand days by approximately 2.0 MVA. This amount of load reduction would need to be implemented before summer 2018-19, and be suitably located within the Carrum Downs / Dandenong South / Sandhurst area that are presently supplied by DVY 24 feeder.



2018-19

EL 10

EL 10 is a highly utilised feeder. It is proposed to build a new feeder from the EW zone substation to offload this feeder. The estimated cost of this augmentation is $1.2 million.

In order to defer the proposed augmentation by twelve months, a non-network solution would need to reduce the summer maximum demand on EL 10 feeder, between the hours of 14:00 to 19:00 on maximum demand days by approximately 4.0 MVA. This amount of load reduction would need to be implemented before summer 2018-19, and be suitably located along the Glen Huntly Rd in the Elsternwick area that is presently supplied by EL 10 feeder.

The main contribution to the summer maximum demand comes from the commercial sector demand on hot summer days. Opportunities for demand reduction therefore exist in the commercial voluntary load reduction schemes.


2018-19

FSH 33 FSH 33 is a highly utilised feeder. It is proposed to extend the lightly utilised FSH 12 feeder to offload FSH 33 to enable better utilisation of assets. The estimated cost of this

2018-19

Strategy



Feeder limitation

Preferred network solution Timing (before summer)

augmentation is $330,000.

In order to defer the proposed augmentation by twelve months, a non-network solution would need to reduce the summer maximum demand on FSH 33 feeder, between the hours of 16:00 to 20:00 on maximum demand days by approximately 0.5 MVA. This amount of load reduction would need to be implemented before summer 2018-19, and be suitably located within the Mount Eliza and Frankston South area that is presently supplied by FSH 33 feeder.


FTN 23

Permanent load transfer away from FTN 23 feeder onto FTN 25 feeder. It will increase the feeder spare capacity at FTN 23. The estimated cost of this augmentation is $26,000.

In order to defer the proposed augmentation by twelve months, a non-network solution would need to reduce the summer maximum demand on FTN 23 feeder, between the hours of 16:00 to 21:00 on maximum demand days by approximately 0.5 MVA. This amount of load reduction would need to be implemented before summer 2018-19, and be suitably located within the Carrum Downs / Seaford / Skye area that are presently supplied by FTN 23 feeder.

The main contribution to the summer maximum demand comes from the commercial sector and the residential sector air-conditioning demand on hot summer days.


2017-18

MGE 12

Establish new high voltage feeder from Mulgrave (MGE) zone substation. Once commissioned, the highly utilised MGE 12 distribution feeder shall be offloaded. The estimated cost of this augmentation is $1.4 million.

In order to defer the proposed augmentation by twelve months, a non-network solution would need to reduce the summer maximum demand on MGE 12 feeder, between the hours of 11:00 to 18:00 on maximum demand days by approximately 3.7 MVA. This amount of load reduction would need to be implemented before summer 2018-19, and be suitably located within the Scoresby and Wheelers Hill area that is presently supplied by MGE 12 feeder.

The main contribution to the summer maximum demand comes from the commercial sector.


2018-19

Next steps

UE intends to implement the preferred network augmentations to alleviate the limitations on the abovementioned distribution feeders, in the absence of any commitment from interested parties to offer alternate network support services.

UE therefore invites interested parties to submit their proposal now to defer or avoid the proposed network augmentations.

Strategy



7 Demand management activities

UE is committed to maintaining long-term supply reliability to our customers in an economically sustainable and environmentally responsible manner. Our network development and planning involves the process of selecting technically and economically accepted projects, regardless of whether they are network or non-network solutions.

UE defines non-network solutions as projects or programmes undertaken to meet customer demand by shifting or reducing demand on the network in some way, rather than increasing supply capacity through network augmentation.

7.1 Network Support Agreements in the past year

Through our actions to promote non-network solutions, in the last two years UE identified economic demand management solutions to successfully defer the proposed augmentation on two distribution feeders, CRM 35 and MGE 12.

UE signed a Network Support Agreement with non-network services provider GreenSync Pty Ltd for two years, to provide 1.0 MW of demand management support on distribution feeder CRM 35, commencing from summer 2014-15. This service was called upon by UE when the network capacity in the area was insufficient to meet the peak demand (during summer periods). The agreement has now ended after two years of support due to a reduction in the VCR following AEMO’s 2014 VCR survey.

UE also signed a second Network Support Agreement with non-network services provider GreenSync Pty Ltd for one year, to provide 0.8 MW of demand management support on distribution feeder MGE 12, for summer 2015-16. This service was called upon by UE when the network capacity in the area was insufficient to meet the peak demand (during summer periods). The agreement has now ended after one year of support due to a reduction in the VCR.

7.2 Demand Management Incentive Scheme initiatives in the past year

The Demand Management Incentive Scheme (DMIS) provides a limited regulatory allowance for UE over the regulatory period to fund projects that lead to the development of efficient non-network solutions to defer planned network augmentation. For the 2011-2015 regulatory control period, UE was allocated $400k pa in the AER’s EDPR determination ($2M over five years) as an ex-ante allowance under the Demand Management Innovation Allowance (DMIA). UE spent this full allocation by the end of the regulatory period on the following three projects:

District Energy Services Scheme (DESS) - Doncaster Hill

Virtual Power Plant (VPP) Pilot

Bulleen Demand Response (Summer Saver) Pilot

For the 2016-2020 regulatory control period, UE has been allocated $400k per annum in the AER’s EDPR determination ($2M over five years) as an ex-ante allowance under the Demand Management Innovation Allowance (DMIA). We encourage non-network service providers approach UE (Refer to Section 9 of UE Demand Side Engagement Document37 for further detail)

37 https://uecdn.azureedge.net/wp-content/uploads/2015/09/Demand-Side-Engagement-Document.pdf

https://uecdn.azureedge.net/wp-content/uploads/2015/09/Demand-Side-Engagement-Document.pdf

Strategy



to enquire about opportunities to use DMIS funding for joint planning activities requiring specific studies, investigations or trials that may lead to the establishment of a non-network solution within the UE service area, in preparation for a future RIT-D. The non-network proponent should provide UE an explanation of the non-network project for which DMIS funding is sought including:

The nature and scope of the project.

The aims and expectation of the project.

Information on how the project will be implemented.

Identification of benefits arising from the project, including any off-peak or peak demand reductions.

Information on the costs of the project, including business case for the project and consideration of any alternatives.

A description on how the proposal helps to meet the objectives of the DMIS.

The DMIS funded projects UE had successfully undertaken in the last regulatory control period are discussed in detail below.

7.2.1 District Energy Services Scheme

In late 2011, UE formalised a Memorandum of Understanding (MoU) with the Manningham City Council (Council) to work with the Council in providing support for jointly planned initiatives within the Doncaster Hill Smart Energy Zone precinct. This joint planning MoU allows UE to provide its expertise in electricity distribution to assist the Council to explore and facilitate projects which promote:

Smart energy efficiency and greenhouse gas reductions; and

Sustainable energy development and demand management opportunities.

The establishment of this MoU coincides with the lead-up to a forecast distribution network constraint in the Doncaster / Templestowe area. UE has identified the most likely network option is to either install a fourth transformer at the existing Doncaster zone substation or establish a new zone substation in Templestowe.

DMIS funding has been used to explore options with Council to manage maximum demand and potentially defer planned network augmentation. The joint planning identified a commercially viable non-network solution in the form of a District Energy Services Scheme (DESS) for Doncaster Hill.

In 2012, UE and Council used DMIS funding to engage two District Energy Service Providers to undertake a commercial feasibility study into a DESS in Doncaster Hill with an objective to defer the planned network augmentation at Doncaster zone substation. Both Service Providers concluded that such a scheme was commercially viable.

Following a detailed verification review of both providers’ proposals in 2013, the Council identified a preferred provider for a DESS for the Doncaster Hill Principal Activities Area. UE plans to continue and facilitate discussions and commercial negotiations in the lead-up to the future RIT-D

Strategy



to maximise the opportunity for a viable, competitive non-network solution to defer the planned network augmentation and address this emerging network constraint.

7.2.2 Virtual Power Plant Pilot

In 2014, UE commenced the Virtual Power Plant (VPP) Residential Pilot Project. The project explores behind the meter installation of solar PV and controlled battery storage technology to incrementally address immediate capacity shortfalls on the LV Distribution Network. Thirteen VPP units were installed on the UE network as part of the pilot project to test the following objectives:

1. Validate the use of solar PV and controlled battery storage technology at residential customer premises to shave peak demand and defer traditional network augmentation;

2. Assess if battery storage technology can be used as an incremental approach to address immediate capacity shortfalls on the LV Distribution Network;

3. Test the current state of the technology and its ability to scale;

4. Identify the risks and test the controls;

5. Develop an understanding of the economics of the solution and validate the solution is a viable load management tool by exploring and then testing the business model(s), taking the generation, retail and distribution aspects into consideration; and

6. Explore and test the contractual and commercial agreements with third parties and residential hosts.

Key project milestones accomplished by UE include:

Pre-implementation study: The pre-implementation study involved developing predictive, economic and commercial models to evaluate the long term feasibility of the project.

Technology: A review of different technologies and suppliers was done with selection based on the most appropriate solution for Australian conditions and the UE network.

Risk Assessment: A full technical and commercial assessment was conducted in line with UE’s risk management process.

Site Selection: Detailed selection criteria were developed by UE to ensure that customer sites selected to participate in the pilot program maximised the lessons learnt.

Installation: Experience gained during the rollout has improved and refined UE’s installation process which has resulted in increased efficiencies. Minor issues encountered early in the trial caused minor delays and increased cost.

Operational Update / Learnings: The thirteen sites have been operational since July 2014, with over a year of operational data recorded. UE simulated a peak network load event in Jan 2015 where the batteries were discharged in ambient temperature conditions of 40°C to shave peak load. The systems operated successfully as per UE’s high temperature control strategy on those peak demand days.

Strategy



Temperature Testing: Lab testing was undertaken to understand how the VPP units operated in extreme temperature conditions. This testing was based on the conditions from the summer of 2009 (which led to the Black Saturday bushfires). The lab testing showed that VPP systems could operate as expected over consecutive extreme temperature days.

UE plan to use VPP technology to demonstrate its feasibility to defer LV network augmentation projects in 2015-16.

7.2.3 Bulleen “Summer Saver” Demand Response Pilot

UE continued it’s Summer Saver Trial during summer 2015-16 in the Bulleen and Lower Templestowe area while extending the trial area to include some highly utilised distribution transformers and low-voltage circuits at an elevated risk of overload outages during summer. More than one thousand customers from all targeted areas registered for the trial.

Figure 131 - Logo for Summer Saver Trial 2015-16

Once registered, participants were requested to voluntarily reduce their power usage on a small number of hot weather ‘event days’ which typically were on weekdays over the summer period. Customers were notified at least two days in advance of an ‘event day’ so they could plan how to reduce their energy consumption. Customers who lowered their energy consumption were rewarded with if they successfully lowered their energy consumption for the event period.

A more comprehensive marketing campaign compared with the previous summer resulted in higher take up rate of approximately 6%. Most of the previous summers’ customers continued on with the trial with some participating in the air conditioner load control program, pool pump load control program or the supply capacity limiting program.

UE called four events in summer 2015-16 with the event days predominantly falling on weekdays with one weekend event day. UE noted a high participation rate with an average reduction in demand of 30% per participant with 70% average participation rate per event. The event time of 4pm-7pm that was consistent for all event days successfully captured the network peak.

UE plans to transition the Summer Saver Trial into a business-as-usual programme for summer 2016-17 using a similar voluntary model, targeting constrained areas of the network to defer augmentation.

Strategy



7.3 Actions taken to promote non-network solutions in the past year

UE has undertaken the following actions to promote non-network proposals in the last twelve months:

UE reviewed and published its Demand Side Engagement Document in July 2016 as part of the three-year review cycle, taking on board feedback from stakeholders.

UE has maintained our Demand Side Engagement (DSE) Register for customers, interested groups, industry participants and non-network service providers who wish to be regularly informed of our planning activities. As at 30 th November 2016, UE had 51 registered organisations including 63 individuals on our DSE Register. Interested parties who wish to be included on our register should fill out their details on our website at:


UE has notified all registered participants on our DSE Register of non-network opportunities identified in our 2015 DAPR and invited alternative proposals to defer or avoid the proposed network augmentations.

UE invited all registered participants on our DSE Register to a public forum held in February 2016 to discuss the identified network limitations in our DAPR and non-network opportunities in further detail.

UE engaged with councils by facilitating and presenting at the Future Energy Planning Forum event held in Melbourne in October 2016, which follows on from a similar event held by UE in January 2015 where UE invited all local government councils within our service area to a forum to discuss the identified network limitations in our DAPR and non-network opportunities. The forum was a way to initiate on-going joint planning relationships with councils. A number of meetings were subsequently held with individual councils.

UE participated in AER hosted workshop on how to design a scheme to encourage efficient demand management in September 2016.

UE has established joint planning Memorandum of Understanding (MoU) with five parties in 2013-14, with two parties in 2014-15 and with one more party in 2015-16. The MoUs facilitate a partnering arrangement which allows the free exchange of information and joint planning between parties well before a RIT-D to formulate alternative options for augmentation projects. This framework has led to UE signing two network support agreements with one of the parties to defer planned distribution feeder augmentations.

UE has developed a standard Network Support Agreement for negotiation with non-network service providers to formalise and define non-network support services when an economic non-network solution is identified.

UE has notified all registered participants on our DSE Register of our RIT-D consultation reports in relation to the Lower Mornington Peninsula and Notting Hill Supply Area RIT-Ds and sought alternative credible solutions.

UE has actively engaged with interested parties to identify, develop and quantify credible non-network solutions as alternative to proposed network augmentation. This resulted in


Strategy



the identification of an economic demand management solution, as a deferral option to distribution feeder augmentation.

UE has published metered zone substation demand data for a 10-year period on our web-site to facilitate development of non-network solutions.

UE has published a constraint map on United Energy’s website to highlight the geographical location of Sub-transmission, Zone Substation and Distribution Feeder limitations for the non-network service providers.

7.4 Plans for future non-network solutions

UE recognises early engagement with non-network service providers is critical for successful and efficient implementation of non-network solutions. In order to promote non-network proposals in the future, UE is committed to:

Informing all registered participants on our DSE Register of non-network opportunities identified in this DAPR.

Inviting all registered participants on our DSE Register to a public forum to be held in early 2017 to discuss identified non-network opportunities in further detail.

Informing generator connection applicants at the enquiry stage of potential non-network opportunities.

Exploring the use of joint planning MoU with other interested parties.

Maintaining our DSE Register.

Actively engaging with interested parties to submit credible alternative proposals to address identified network limitations in this DAPR.

Investigating and evaluating each non-network solution (including network augmentations) using identical criteria that reflect both the regulatory requirements under the NER and our desire to implement the least lifecycle cost solution to address the identified need. This process is set out in more detail in Section 4.1 of our Demand Side Engagement Document.

Exploring the use of Demand Management Incentive Scheme (DMIS) and Demand Management Innovation Allowance (DMIA), a regulatory allowance over this regulatory period, to fund projects that lead to the development of efficient non-network solutions to defer planned network augmentations.

Exploring the use of smart meters which have been rolled out across the UE network to enable customers to actively participate in the management of their energy use through the provision of timely, relevant information and control options. Smart meters give the ability to apply enhanced tariff arrangements, energy management, customer signalling and more sophisticated power usage monitoring.

Strategy



7.5 Connection of Embedded Generation (EG) units

On 1st October 2014, the Australian Energy Market Commission (AEMC) established new requirements in Chapter 5 of the National Electricity Rules.38 These changes require the distribution businesses to better facilitate the connection of embedded generation in the NEM and to report on the following matters in the DAPR:

Key issues from applications to connect EG units over the past year; and

A quantitative summary of connection enquires and applications to connect EG units received since 1st October 2014.

UE undertakes the connection process for embedded generator connections in accordance with Chapter 5 and Chapter 5A of the NER.

Chapter 5

Applicable for all embedded generation with capacity above 5MW

These generators must be registered (as per NER definition) or apply for an exemption with AEMO.

This process is generally for larger embedded generation connections at distribution and or transmission high voltage level such as wind farms or peaking synchronous generators.

Chapter 5A

Applicable for majority of below 5MW capacity embedded generation

These are non-registered generators (as per NER definition)

This process is generally for smaller embedded generation connections at distribution high and or low voltage such as solar or small scale co/tri-generation systems.

A connection applicant with a generator connection below 5MW may choose to use the Chapter 5 connection process. This must be requested in writing to UE.

The merits of each connection process is briefly outlined below:

Chapter 5 Chapter 5A

More defined and detailed More flexible

Generally longer Generally shorter

Further details on these matters are provided in Section 4.2.3 of UE Demand Side Engagement Document39.

38 For connection application greater than 5 MW. 39 https://www.unitedenergy.com.au/industry/mdocuments-library/


Strategy



7.5.1 Key issues from applications to connect EG units in the past year

The potential issues that can be encountered in the connection of embedded generation are numerous, and depend greatly upon the specific location and proposed project. UE has identified the following issues associated with the application process to connect embedded generation units over the last year:

Market developments are significantly influencing the economic viability of all generation type and scale. Proposal capacity and complexities have also been observed to be gradually increasing. Forecasting of project volume in this arena has, historically been difficult and highly unpredictable. As a consequence, the ability to facilitate proposals are constantly challenged, in particular from a resource perspective due to the specialist technical nature involved and evolution of project complexities.

Obligations and liabilities need to be assessed on a case-by-case basis and negotiated with the proponents. For example, requirements and / or potential impact to other non-embedded generator customers as well as proponent’s own installations can vary with each connection application.

Technical standards and the regulatory framework have not been evolving to keep pace with market developments and the introduction of new technologies (especially in the area of energy storage) are significantly lagging. The immaturity and structurally embryonic state of these domains have been recognised by the wider industry. As a result, an industry wide initiative to bridge these gaps are emerging, but these developments will take time to filter through.

The fast evolving nature of the EG industry along with many new market entrants is increasing the diversity and spectrum of proponent and their capabilities. Consequently the technical nature of EG connection process challenges some proponents more than others with some projects requiring an increased engagement with the proponent. Such projects typically extend longer than originally envisaged with multiple iterations not uncommon accompanied by periods of hiatus for the proponent to appreciate and digest the technicalities to successfully comply with the connection criteria.

Project coordination challenges are not uncommon particularly for complex proposals given multiple parties are involved at various stages of the connection application process (i.e. UE / Connection Applicant / Design consultants / Primary constructor and sub-contractors etc…).

7.5.2 Quantitative summary of connection application to connect EG units

The table below provides a quantitative summary of connection enquires and applications to connect EG units received between 1st July 2015 and 30th June 2016.

Strategy



Table 27 – Summary of embedded generation connections40

Description Quantity (> 5MW)

Connection enquires under 5.3A.5 2

Applications to connect received under 5.3A.9 0

The average time taken to complete application to connect N/A (preliminary enquiries only)

40 The reporting period is over 12 months commencing from 1st July 2015 to 30th June 2016.

Strategy



8 Network performance

8.1 Network reliability

8.1.1 Reliability performance measures and targets

Delivering an electricity supply of appropriate reliability and quality to customers is UE’s core business. In order to measure UE’s effectiveness in achieving this, a number of performance indicators are used. These include:

SAIDI is the system average interruption duration index and reflects the number of minutes the average customer is without electricity supply during the year.

SAIFI is the system average interruption frequency index and reflects the number of sustained interruptions that affect the average customer during the year.

CAIDI is the customer average interruption duration index and reflects the average duration of interruption for customers affected by outages (not all customers are impacted by outages). This reliability performance index indicates the average restoration time for each event and is used as a measure of a utility’s response time given adequate levels of redundant capacity to system contingencies.

MAIFIe is the momentary average interruption frequency index and reflects the number of momentary interruptions the average customer experiences during the year. The small letter “e” stands for “event” where an event consists of one or more momentary interruptions occurring sequentially in response to the same cause that does not result in a sustained loss of supply.

UE’s reliability performance targets for the current regulatory period have been set by the Australian Energy Regulatory (AER).41 These targets are based on the average reliability performance from the preceding regulatory period, adjusted to take into account any reliability improvement initiatives or other factors that have a material impact on the network.

Table 28 below provides UE’s reliability performance targets for the current regulatory period.

Table 28 – Reliability performance target levels

UE reliability performance target levels

Reliability measures 2016 2017 2018 2019 2020

SAIDI unplanned (minutes) 69.8 69.8 69.8 69.8 69.8

SAIFI unplanned (interruptions) 1.00 1.00 1.00 1.00 1.00

CAIDI unplanned (minutes) 69.6 69.6 69.6 69.6 69.6

MAIFIe unplanned (interruptions) 1.12 1.12 1.12 1.12 1.12

41 The current EDPR period is 2016 to 2020. AER specifies network targets based on both urban and short rural designations for UE.

These targets are aggregated based on forecast changes in urban, rural designations over the EDPR period to forecast the reliability targets for the current regulatory period.

Strategy



8.1.2 Reliability performance

The table below shows UE’s actual performance against those targets in the 2015 calendar year. This information was submitted to the AER in our Regulatory Information Notice (RIN). In addition, the table shows the forecast performance for the 2016 calendar year.

Table 29 – Reliability performance Actual vs. Target

Reliability measure 2015 actual performance 2016 forecast performance

Actual Target Forecast Target

SAIDI unplanned (minutes) 66.3 57.3 60.5 69.8

SAIFI unplanned (interruptions) 0.91 0.94 0.90 1.00

CAIDI unplanned (minutes) 72.9 61.0 67.4 69.6

MAIFIe unplanned (interruptions) 1.01 1.13 1.08 1.12

In 2016, UE customers are forecast to experience better than target reliability performance as a result of a reset of UE’s regulatory targets. The improved network performance is forecast to improve compared with 2015 actual performance due to:

Increased network sectionalisation.

Reduced frequency of equipment failure events due to targeted asset replacement programs in 2015.

Improved restoration times compared with 2015.

The figure below shows the major causes of supply interruption on our distribution network.42

Figure 132 – Causes of supply interruption

42 UE: 2015 Regulatory Information Notice (RIN)

11%

18%

35%

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7%

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Weather Vegetation Equipment Failure Third Party Impact Other Animals

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The figure above shows that the major cause of supply interruption on the UE network is equipment failure. Figure 133 below shows the impact of equipment failure on the performance of our network in recent times.

Figure 133 – Impact of equipment failure events on reliability

The figure above shows that impact of equipment failure on reliability has increased in recent times despite a one-off improvement in 2015. The increasing trend in equipment failure events is mainly attributed to an increasing number of assets approaching the end of their life. In the absence of any corrective actions, it is anticipated that the levels of asset failure impacting customer reliability would continue to increase in the future. In order to reverse this trend, UE is committed to continue capital investment in preventative maintenance and asset replacement programmes focused on optimising the required expenditure against network reliability and safety outcomes to ensure that only prudent and effective expenditure are made. Details of significant asset replacement programmes are outlined in Section 9.2.

The other major cause of supply interruption on our network is weather and vegetation related incidents. Although the supply interruptions due to these factors are relatively minor, their impact on reliability has increased progressively over the time horizon as shown in Figure 134.

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Strategy



Figure 134 – Impact of weather and vegetation related events on reliability

Given UE’s network is predominantly overhead, it is anticipated that the actual network performance is likely to vary significantly from one year to the next. Although some factors may be outside of UE’s control, we are undertaking significant vegetation management to maintain adequate clearance around the overhead network, in accordance with Electric Line Clearance Regulations 2010. However, vegetation beyond the clearance area has contributed to supply interruptions during severe weather events. UE is working closely with our stakeholders to evolve and improve our relationships, with more cooperation between parties enabling effective tree management.

8.1.3 Reliability performance review process

UE undertakes a monthly review of the reliability performance during the previous month and on a rolling twelve-month basis to:

Review the actual network performance.

Identify network performance trends.

Identify pockets of the network that require targeted investment.

Review ‘rogue’ feeders for viable initiatives to maintain reliability.43

Identify management strategies to improve reliability.

The aim of these reviews is to maintain the reliability to our customers in a strategic, targeted, and cost-effective manner via a number of reliability correction actions and initiatives described below.

43 The worst performing high voltage feeders on a rolling twelve-month basis are classified as ‘rogue’ feeders and are targeted for

improvements.

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Strategy



8.1.4 Reliability corrective actions and initiatives

UE is committed to continue significant capital investment in its electricity network together with operating expenditure on maintenance, vegetation management and asset inspection programmes with the expenditure in line with the allocations provided by the AER in this regulatory period. The investment is in response to the need to continually renew the network, reduce the levels of asset failure impacting customer reliability, improve supply restoration times, develop infrastructure appropriate to the needs of the growing community and support the continued economic growth and prosperity of south eastern Melbourne and the Mornington Peninsula.

Primarily UE’s reliability is affected by its growing proportion of assets that are in their last 15% of their engineering lives and severe weather resulting in both weather and vegetation related outages.

UE’s program of work will enable it to, on average over the 2016 – 20 period, meet its regulatory targets contained in the AER’s regulatory determination for the period.

The following provides a summary of the major reliability improvement initiatives:

Vegetation management

Vegetation management includes the inspection, liaison and cutting activities associated with the control of vegetation for the primary purpose of compliance with the Electric Line Clearance Regulations 2010. UE initiates cyclic, targeted vegetation management by prioritising feeder sections based on multiple drivers including customer numbers, history of vegetation related faults, high risk bushfire areas and current programme status. UE will continue to work closely with our stakeholders to evolve our relationships, with more cooperation between parties enabling better tree management.

Asset replacement programmes

In addition to the reliability improvement programmes, UE has increased its reliability focus in connection with asset maintenance and asset replacement strategies. Some of the asset maintenance and replacement strategies that will either continue to have positive influence on reliability performance or provide additional benefits on reliability performance in the coming years of this regulatory period are as follows:

Line defect refurbishment.

Conductor replacement.

Underground cable defect replacement.

Pole top inspection programme and pole top replacement.

Sub-transmission line refurbishment and replacement.

Substation primary plant condition based replacement.

Ampact connector replacement.

Strategy



Remote control and monitoring of field switches

UE propose to continue installing Auto Circuit Reclosers (ACR), Remote Control Gas Switches (RCGS) and monitoring equipment on existing switches so that the high voltage feeders can be monitored and controlled centrally from UE’s Network Coordination Centre (NCC). These devices enable the NCC to quickly locate a fault and restore supply to customers, speeding up response and supply restoration times to further reduce the impact of faults on customers.

8.1.5 Information submitted to the AER

UE provides information on its network reliability performance indicators to the AER. These indicators are reported annually.

A summary of network performance indicators contained in the most recent submission to the AER is presented in table below.

Table 30 – Network performance indicators submitted to the AER44

UE reliability performance






8.1.6 Reliability performance forecast

Forecasting future reliability performance is an inherently difficult undertaking, with variability of weather impacts making it difficult to provide an accurate prediction of performance for any given year. Reliability outcomes are usually attributed to a combination of factors and not just the targeted reliability improvement works. For example, business as usual maintenance and refurbishment works, improved operational practices, network augmentation and favourable weather conditions impacts positively on reliability outcomes collectively.

The following table shows the forecast network performance for the regulatory period of 2016 – 2020.

Table 31 – Reliability performance forecasts

UE reliability performance forecasts






44 These figures are based on relevant exclusions at the time of reporting.

Strategy



8.2 Power quality

UE is committed to not only a reliable supply for all customers but also ensuring power is delivered at a high quality. The projects and initiatives on power quality by UE address power quality regulatory compliance requirements and halt the deterioration in quality of supply levels on UE’s network. The expenditure levels during the 2011-2015 period demonstrate that UE has addressed the identified power quality compliance issues through prudent programs of work. These programmes continue in the 2016-2020 regulatory control period to maintain power quality. Furthermore, an increase in expenditure in some areas is required in response to increasing numbers of installed solar photovoltaic (PV) systems at customers’ premises. The regulatory obligations are to measure network power quality and to correct power quality where it is not within the codified limits. UE performs this by targeting power quality programs towards the worst-served customers first where there is an economically prudent case to do so.

Power quality encompasses the parameters of steady-state voltages, voltage sags (dips), voltage swells (surges), flicker, harmonic distortion and unbalance of voltage for three-phase supply.

Customer expectations regarding the reliable operation of sensitive equipment and the substantial increase of power-electronic equipment used in industry has raised the importance of power quality.

UE is facing significant challenges in the area of power quality. These challenges include:

Increasing numbers of residential solar photovoltaic panels on the distribution network creating steady-state voltage management challenges, particularly local over-voltages.

Increasing customer expectations due to the proliferation of devices and appliances that are perceived to be more sensitive to network power quality issues, particularly devices that are impacted by momentary voltage sags.

Managing the implications of disturbing loads connected to ‘weaker’ parts of the network or parts of the network shared with other customers, particularly for short-term flicker.

Increasing penetration of non-linear loads on the distribution network increasing network harmonic voltage distortion, particularly the 5th harmonic current created by power-electronic equipment.

8.2.1 Power quality strategy

Management of network power quality is a continuing focus for UE and strategies are focused on establishing or improving UE’s capabilities to assess the quality of supply including:

Establishing new strategic power quality metering points;

Improving existing power quality monitoring capability;

Leveraging the power quality capabilities of Advanced Meter Infrastructure (AMI) (smart meters);

Developing meaningful power quality indices;

Evaluating the financial costs of power quality disturbances for the customers;

Strategy



Implementing solutions to maintain power quality within regulatory limits; and

Implementing processes to ensure equipment that has the potential to cause poor quality of supply are connected in the correct manner.

This approach provides a proactive framework for monitoring and addressing power quality issues on the network. UE’s aim is to:

Maintain the current performance and prioritise the power quality issues experienced by the worst served customers.

Minimise interruptions to customers due to network induced voltage disturbances.

Reduce the level of network losses generated by voltage unbalance and harmonics.

Encourage industry development of power quality standards and strategies.

Address any emerging issues identified as being associated with power quality with appropriate mitigations.

Minimise risk of damage or loss of life to customer and network equipment caused by power quality disturbances.

8.2.1.1 Power quality monitoring capability

UE regards a proactive approach to power quality monitoring as an essential activity for detecting or foreseeing power quality disturbances on the distribution network. This is achieved by using a system of sophisticated power quality meters located at strategic points across the network. Not only can a monitoring system provide information about system disturbance events and their possible causes, it can also detect potential problematic conditions throughout the network before they cause customer complaints, equipment malfunctions and even equipment damage or failure. The source of power quality issues is not necessarily limited to the supply-side of the network but many power quality problems are localised within customer facilities. Given this, power quality monitoring is not only an effective customer service strategy, but also a way to better manage quality of supply on the distribution network.

Currently, every UE zone substation has at least one power quality monitoring device permanently installed on site. For those zone substations with a split bus (either temporary or permanent), a power quality monitoring device is installed on each bus. A power quality monitoring device is also installed at the far end of one feeder emanating from each zone substation, usually the longest feeder as illustrated in Figure 135.

Strategy



Figure 135 – The present coverage of PQ monitors on UE network

Customer power quality monitors currently installed at the customer connection point, as part of the AMI program, measure the voltage and current. The table below presents the capability of existing power quality monitors.

Smart meters at

all <160MWh customer

connection points

No PQ monitors at distribution substations

PQ

monitors at all zone

substation

s

No PQ

monitors at transmission connection

points

PQ monitors at some

large customer

connections

PQ

monitors at end of the

longest MV

feeder from each zone substation

Strategy



Table 32 – PQ measurement capability of installed power quality monitors

PQ disturbances Zone substation End of feeder45 AMI meters

Steady-state voltages

Voltage sags and swells

Under / over voltages

Transient

Voltage unbalance

Harmonics 46

47

Flicker 48

UE currently has no power quality metering capability to continuously monitor power quality at transmission connection points or distribution substations (except end of feeder meters). UE also has limited capability to monitor inter-harmonics and flicker.

UE intends to address these shortcomings, over the 2016-2020 regulatory control period, by:

Installing power quality monitors at each transmission connection point.

Installing power quality monitors at selected large or critical customer sites.

Installing power quality monitors on targeted medium-voltage feeders (not necessarily the longest feeder).

8.2.1.2 Power quality analysis

The importance to measure, categorise, benchmark and publish network power quality levels cannot be under-estimated. UE’s network is predominantly overhead and is subject to the influence of natural elements such as vegetation, weather, animal and bird contacts. Short-term voltage variations such as voltage sags and voltage swells cannot be eliminated without significant network investment. A balance needs to be struck between hardening customer electrical equipment to ‘ride through’ momentary events and network investment. In addition, the increasing penetration of non-linear loads such as computers and compact fluorescent globes is contributing to the increase in network harmonics.

To this end, UE participates in the Power Quality Compliance Audit (PQCA), formerly known as the Long-Term Network Power Quality Survey (LTNPQS) conducted by the University of Wollongong. The survey establishes ‘typical’ power quality characteristics that can be reasonably delivered by distribution networks.

The survey is conducted annually, and is heavily reliant on power quality monitoring data.49 The PQCA provides analysis of steady-state voltages, voltage unbalance, voltage harmonics, voltage sags and flicker.

45 Includes large customers. 46 Total Harmonic Distortion (THD) and Individual HD. 47 THD only. 48 Not all zone substations. 49 UE has provided data from 49 low-voltage sites and 78 medium-voltage sites with the average coverage of 98% and 99% in FY 2015-16, respectively.

Strategy



8.2.1.3 Power quality management process

UE is continuing to refine and develop an end-to-end process which enables the rapid identification of power quality disturbances, their investigation and deployment of appropriate solutions. This initiative is targeted at ensuring that power quality issues raised by customers, the power quality monitoring program undertaken by PQCA and UE are dealt with in an efficient, consistent and auditable process. This process includes thorough investigation, application of options and delivery of desired improvement outcomes.

8.2.2 Power quality standards

UE is required to comply with Section 4 of the Victorian Electricity Distribution Code (The Code) and Schedule 5.1a of the National Electricity Rules (NER). In addition, UE must:

Provide power quality performance report to the Australian Energy Regulator (AER).

Provide power quality information to customers and retailers (where applicable).

In many areas of power quality, the two regulatory requirements overlap and set differing obligations. UE therefore plans the network to comply with power quality limits that are the more stringent of the two regulatory requirements.

A summary of critical power quality indices are specified below in Table 33 to Table 36.

Table 33 – Allowable variations from the relevant standard nominal voltages

Voltage levels The Code NER

Low voltage (less than 1 kV) +10% / -6% +10% / -10%

Medium voltage (1 kV to 22 kV) +6% / -6%50 +10% / -10%

High voltage (66 kV) +10% / -10% +10% / -10%

Table 34 – Allowable voltage unbalance limits

Voltage levels The Code51 NER

Low voltage (less than 1 kV) 1% 2.5%

Medium voltage (1 kV to 22 kV) 1% 2%

High voltage (66 kV) 1% 2%

Table 35 – Allowable voltage total harmonic distortion limits


Low voltage (less than 1 kV) 5%52 8%

Medium voltage (1 kV to 22 kV) 3%53 6.5%

High voltage (66 kV) 3% 3%

50 Voltage variation of +10%, -10% is applicable for rural areas. 51 Voltage unbalance can be 2% for a total of 5 minutes in every 30 minute period. 52 4% of odd individual voltage harmonic distortion and 2% of even individual voltage harmonic distortions are allowed. 53 2% of odd individual voltage harmonic distortion and 1% of even individual voltage harmonic distortions are allowed.

Strategy



Table 36 – Allowable flicker limits


PST PLT PST PLT

Low voltage (less than 1 kV) 1.0 0.8 1.0 0.8

Medium voltage (1 kV to 22 kV) 0.9 0.7 0.9 0.7

High voltage (66 kV) 0.8 0.6 0.8 0.6

8.2.3 Power quality performance

8.2.3.1 Steady state voltage

Power quality monitoring has revealed that in some instances the steady-state supply voltage is outside the regulatory limits. The AMI metering has also identified that there are a large number of customers experiencing steady-state voltages outside the high side of the regulatory limit. This issue was previously unknown due to the absence of continuous voltage monitoring on the low-voltage network and has been revealed by UE’s population of smart meters. It is likely this issue has been in existence for many decades, but is likely to be exacerbated over-time by the increasing penetration of roof-top solar photovoltaic cells at customer premises.

According to the FY2015-16 PQCA results, about 12% of the low-voltage sites exceed the upper voltage limit of 1.1 per unit (253V), while 14% of the medium-voltage sites exceed the upper voltage limit of 1.06 per unit as shown in the figures below.54 For the voltage distribution, upper and lower parts of bars indicate 99th and 1st percentile values, respectively.

54 UE has supplied data for 78 MV sites for steady state voltage. All sites had coverage (percentage of the survey period for which data is available) of greater than 25% of the survey period and as such are included in the PQCA utility and national results.

Strategy



Figure 136 – Steady state voltage distribution for LV sites during 2015-16 (Financial year)

Figure 137 – Steady state voltage distribution for (a) 6.6kV and (b) 11/22kV sites (50 worst sites) during 2015-16 (financial year)

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(b)

To proactively respond to non-compliance steady-state voltages, UE query the AMI metering by exception, reporting only those customers outside the regulatory limits. These customers are then aggregated by common asset class to determine if the voltage problems are occurring in clusters. UE then remedies the voltage by prioritising according to the number of customers in each cluster and the duration for which the voltage excursions are occurring, then implement an ongoing programme to remedy these situations which includes:

Adjusting the tap position at the distribution substation.

Adjusting the voltage set-point at the supply zone substation.

Compensating the reactive power by installation of pole-mounted capacitor banks.

Installing voltage regulators along heavily loaded long lines.

Installing low-voltage regulators.

Augmenting the low-voltage network (low-voltage feeder or distribution substations).

Augmenting the medium-voltage network (medium-voltage feeder).

Undertaking medium-voltage or low-voltage open point changes or load balancing.

8.2.3.2 Voltage unbalance

Voltage unbalance is known to cause overheating in transformers and customer motors due to negative-sequence components created in the unbalance.

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According to the FY2015-16 PQCA results, the voltage unbalance at 99% of the monitored UE sites is below the requirements of the NER55. However, some UE sites are non-compliant under The Code. UE has highlighted the inconsistency in the regulations to the Essential Services Commission (ESC) and the AER with the view of revising ‘The Code’ to be consistent with the national power quality framework.

Figure 138 – Voltage unbalance distribution for LV sites during 2015-16 (Financial year)

55 Voltage Unbalance Factor (VUF): Ratio of negative sequence to positive sequence voltages presented as a percentage.

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Strategy



Figure 139 – Voltage unbalance distribution for (a) 6.6kV and (b) 11/22kV sites (50 worst sites) during 2015-16 (financial year)

(a)

(b)

The worst performing zone substations for voltage unbalance include those that supply rural areas via two-phase or SWER systems.

8.2.3.3 Voltage harmonic distortion

Voltage harmonic distortion can vary significantly across the network. According to the FY2015-16 PQCA results, the voltage harmonic distortion at some monitored UE sites are not within the regulatory limits.

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Figure 140 – Voltage harmonic distortion for LV sites during 2015-16 (Financial year)

Figure 141 –Voltage harmonic distribution for (a) 6.6kV and (b) 11/22kV sites (50 worst sites) during 2015-16 (financial year)

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(b)

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8.2.3.4 Flicker

In general, any load connected to the electricity network which generates significant voltage fluctuations can be the origin for flicker. Such voltage fluctuations are a result of significant cyclic variations, especially in the reactive component. According to the FY2015-16 PQCA results, the flicker levels at all monitored UE medium-voltage sites are within the regulatory limits.

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Figure 142 – Short-term flicker index for (a) 6.6kV and (b) 11/22kV sites during 2015-16 (financial year)

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Figure 143 – Long-term flicker index for (a) 6.6kV and (b) 11/22kV sites during 2015-16 (financial year)

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8.2.3.5 Voltage sags

Voltage sags, caused mainly by network faults depressing voltage levels across the network, are the main concerns customers have regarding power quality. According to the FY2015-16 PQCA results, the voltage sag SAIFI56 at 98% of the monitored UE sites are within the PQCA limit.

Figure 144 – Voltage sag SAIFI distribution for LV sites during 2014-15 (Financial year)

Figure 145 – Voltage sag SAIFI distribution for (a) 6.6kV and (b) 11/22kV sites (50 worst sites) during 2015-16 (financial year)

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56 The index used in the PQCA reports to assess sags.

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(b)

UE has attempted to address the issue of voltage sags with a number of initiatives including improving reliability, limiting fault current, and dynamically changing the point of common coupling. UE intends to further address this issue by introducing a number of new technologies to minimise the severity of voltage sags experienced by customers by reducing the current flowing on the distribution feeders during a fault. Moreover, UE has implemented an economic network solution that helps to improve network performance with regard to voltage sags during network faults. UE has successfully implemented the automatic Bus-Tie Open Scheme at a number of zone substations supplying major industrial customers. This scheme improves voltage-sag performance without compromising system reliability. Given this, UE intends to deploy the scheme to all its zone substations supplying industrial and commercial customers over the next few years.

8.2.4 Power quality corrective actions and initiatives

There were no fundamental issues related to power quality that were not addressed in the FY 2015-16. However, as part of our proactive and continuous improvement culture, UE plans to undertake a number of initiatives in the area of power quality. The initiatives include:

Low-voltage regulator

Many renewable energy generators such as roof-top solar photovoltaic and micro-wind generation schemes are intermittent in their power output. This requires the need to need to investigate localised impacts on network flicker and steady-state voltage profiles.

Application of a low-voltage regulator can potentially tighten voltage spread and provide faster response to sudden changes in voltage. They facilitate the connection of intermittent renewable generation by smoothing out flicker impacts and, when available with remote control functionality, they can be used as a demand reduction / energy conservation measure by reducing the voltage towards the bottom of the regulatory voltage band. At present, the range of sizes for this equipment is limited and they are limited in their use to specific areas of the low-voltage network. Nevertheless, these devices have been installed in areas of the low-voltage that exhibit both steady-state under-voltage and over-voltage issues. UE plans to monitor this development to determine if there is potential migration path to a more localised voltage regulation strategy in the future.

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Develop terminal station power quality monitoring capability

Power quality monitoring is required at terminal stations to better understand power quality at transmission connection points and correlate this performance in the distribution network. Knowing the power quality levels at the connection points will enable UE to determine the components of power quality attributed to the transmission system, other DNSPs sharing connection points or distribution assets, or UE’s own network. This will assist with a better identification of sources of power quality problems, enable UE to confirm power quality simulation models and identify common-mode power quality trends. It will also allow reporting of power quality levels at transmission connection points in the future if required.

This work will be coordinated with AusNet Services Transmission Group and be progressively rolled-out over the 2016-2020 regulatory control period.

Develop AMI power quality metering

The rollout of AMI meters has enabled UE to monitor basic power quality levels at individual customer premises. UE has developed query and reporting tools to aggregate the data into meaningful sets of information and provide exception reporting to better manage the quality of supply to customers such as steady-state voltages, voltage sags and swells and phasing information. UE intends to enhance the AMI architecture to provide an engineering user interface for customer power quality information and to facilitate investigations into poor power quality performance.

Harmonic filtering

Harmonic filters are needed to manage the high levels of voltage harmonic distortion at some zone substations with the capacitor banks out of service or where multiple harmonic frequencies are problematic and where replacement of the inrush reactor alone does not achieve desired detuning effects. UE has already completed installation of harmonic filters at a number of zone substations and plan to additional filters at a number of zone substations with high levels of voltage harmonic distortion that exceed regulatory limits.

Bus-tie open scheme

This scheme limits the severity of voltage sags created by faults on the medium-voltage network by isolating the healthy parts of the network from faulted parts by switching circuit breakers. While this scheme does not reduce the number of faults on the network, it does limit the number of customers exposed to severe voltage sags during a fault, without compromising overall system reliability and plant utilisation. UE plans to install similar schemes at zone substations which are currently experiencing high number of voltage sags.

Trial distribution transformers with on-load tap changer (OLTC) capability

The distribution transformers on the UE distribution network operate on fixed discrete taps and do not operate from an OLTC. However, there are some types of distribution transformer available on the market with an OLTC capability. Therefore, UE plans to trial such transformers to evaluate their performance at regulating the low voltage and mitigating steady-state voltage variations as well as other benefits.

Strategy



Zone substation dynamic voltage regulation trial

In order to trial this method, first the Voltage Spread that provides a measure of the strength of a site needs to be calculated for all of the UE zone substations using the AMI data. The Voltage Spread is the difference between light-load and heavy-load voltage and will determine if the zone substation has the potential for implementing on-load voltage regulation or not.

Analysing the AMI data for the nominated zone substations might reveal the need of some remedy actions to rectify the extreme over/under-voltages before implementing the method.

Once the suitable zone substations are identified, the voltage set-points need to be applied to the voltage regulating relays (VRRs). Note that not all of the existing VRRs are capable of operating with multiple voltage set-points and a new VRR with required capabilities might require to be installed. Moreover, protection settings such as over-voltage, under-voltage, etc. of the HV customers supplied by the nominated zone substations shall be taken into consideration when the voltage set-points are determined.

After implementing this method, the AMI data for all of the customers shall be monitored to ensure they receive a compliant voltage between the stipulated regulatory limits. In order to perform this, the 99th percentile voltage (V99%) and the 1st percentile voltage (V1%) can be utilised.

AMI-based load balancing technique

Due to the dynamic nature of a residential distribution network, it is not possible to achieve a completely balanced load in a low-voltage circuit. This is because the residential customer usage pattern varies at different times of the day. System planners calculate optimum load across the three phases during transformer installation. However, due to network augmentations and changes in customer usage patterns, the low-voltage balance may drift over time.

Unbalance requires more attention to be taken when the distribution transformer has long overhead lines due to higher level of voltage drop and consequently, unbalance which causes more customer to be impacted by the associated detrimental impacts. Therefore, UE needs to rectify voltage unbalance operating conditions via load balancing which are identified by using AMI meter data, customer complaints and information from the field.

In order to perform load balancing, first the current phases of the customers supplied by the question distribution transformer are identified using an AMI-based technique and then, the customers whose phases need to be changed are selected by taking into account their peak demands and average energy consumptions. Load balancing will assist to accommodate a higher number of solar photovoltaic systems into the distribution network.

Correction of loose connections

A common cause of over/under-voltages in distribution networks is loose connections which can even result in fatal electric shocks. Correcting loose connections will reduce line resistance and losses. In addition, failing to fix a loose connection is potentially costly as it may lead to a fault in the network and thus to a power outage. In other words, if a loose connection is left uncorrected, it runs the risk of having to compensate its customers for the damage caused.

Therefore, UE investigates and rectify the potential loose connections using the AMI data. Similar to load balancing, this option will assist to accommodate a higher number of solar photovoltaic systems into the distribution network and reduce the number of customers’ voltage complaints in a proactive manner.

Strategy



9 Asset management

The age profile of UE’s distribution network reflects the large investment that took place in the electricity networks in Victoria with much of the area electrified post-World War. Assets on the UE network were first installed in Melbourne in the early part of 1900s although it wasn’t until the late 1930s that network assets were being installed in large numbers. From the late 1950s the network started growing rapidly, with a large number of new customer connections driven by the economic growth in the post-war decades. During the latter part of the century the capacity of the network continued to grow as air conditioners, computers and other electronic devices drove significant demand growth across the network. Much of this area is now urbanised. The present implication is that an increasing number of assets are approaching their end-of-life and require replacement over the current planning period.

This chapter sets out the asset management framework which seeks to demonstrate the governance framework underpinning the Asset Management System to ensure a line of sight of responsibilities for key documentation deliverables.

9.1 Asset management system

UE is implementing an improved Asset Management System to align activities and documentation into a comprehensive and integrated framework in accordance with ISO 55000 as shown in Figure 146. The Asset Management Strategy and Objectives is highlighted within the overall framework.

Strategy


Figure 146 - Asset Management System

Strategy


The UE Asset Management system intends to:

align with key aspects of the requirements of International Standard 55000 Asset Management series;

provide a clear line of sight to ensure integration between business and Asset Management requirements expressed in the following;

o Corporate Plan and Objectives

o Asset Management Drivers

o Risk Appetite statement

includes the following interdependent document deliverables

o Asset Management Policy - provide overarching principles that align with Corporate Objectives and Asset Management drivers.

o Asset Management Strategy and Objectives for the management of assets that align with the Asset Management Policy.

o Non-Asset and Asset Class plans that describe how each Non-Asset and Asset Class will achieve the requirements of the Asset Management Strategy and Objectives.

o Capex/ Opex Works Program (COWP) outlining the annual works program that is used by Service Delivery to deliver projects.

o Asset Management Plan that provides an overview of Asset Management works programs for a 10 year period.

9.1.1 Asset Management Strategy and Objectives

In order to develop the Asset Management Strategy and Objectives a number of considerations are analysed by UE. These are outlined within UE’s Asset Management Strategy and Objectives document though can be summarised as follows:

1. Long Term imperatives

Safety, reliability and quality of supply

Regulatory requirements

Good asset management practice

Stakeholder needs

2. Recent Developments

Bushfire Royal Commission

Deteriorating reliability

Decreasing energy usage

Slowing peak demand growth

Strategy



Uptake of solar photovoltaics

Aging Assets

Political

3. Drivers of Change

Customer dynamics

Government/market institutions

Energy technology

Network security

Price signals

4. United Energy Business Objectives

Strong Financial Management

Innovation and Continuous Improvement

Customer focus

Future Focus

Winning Culture

5. Asset Management Policy

Employ good asset management practices to prudently manage and operate the assets over their total life cycle.

Minimise our long-term cost structure considering the potential downturn in future grid consumption.

Build our reputation as a trusted company with customers and stakeholders by striving for active industry leadership, agility, reliability, safety and good customer service in light of changing customer and community expectations.

Meet all legal and regulatory requirements.

Adhere to the relevant Australian, international and industry standards and any other requirements to which United Energy subscribes.

Manage reasonably foreseeable and credible safety risks to as low as reasonably practicable.

Develop high performance operations by engaging our people and having the right skills and capabilities within the organisation.

Strategy



Embed continuous improvement and innovate to drive efficiency.

Monitor and evaluate appropriate metrics to effectively manage the network and customer service performance.

9.1.2 Asset Class Strategies and Plans

A key part of UE’s Asset Management System is the development and maintenance of Asset Class Strategies for sub-transmission and distribution asset classes. These strategies describe the management of the various asset classes from creation through to disposal and include the maintenance and replacement strategies applied to each asset. The strategy documents take the high-level asset strategies and objectives and combine them with an in-depth knowledge of the specific assets to identify the requirements that will ensure delivery of optimum outcomes. The group for Asset Class Strategies and Plans are as follows:

Primary Electrical Assets

Secondary Electrical Assets

Fleet

Metering

Operational Property

9.1.3 Asset Management Plan and COWP

The Asset Management Plan (AMP) is list of maintenance projects and renewals projects that have been derived from the Strategic Planning process and is outlined in detail in the Capex and Opex Works Program (COWP).

The COWP explains in detail the execution of the AMP and reflects a two-year budget cycle that is updated quarterly to provide a rolling two-year cycle, setting out the actions, responsibilities, resourcing and time scales for the activities in each program. Expenditures are associated with both capital and operational activities.

The Asset Management Plan is a rolling 10-year plan that translates the asset strategy and asset performance data into a more detailed investment plan. It strikes a balance between efficient and cost-effective investment, the required level of service from the physical assets and an appropriate level of risk to develop a long-term plan. To develop the AMP, UE collects and analyses data, determines the necessary modifications to the network that are required, and then produces a capital plan to deliver the network investments with a rolling 10-year view.

To optimise investments in replacement, demand and performance capital expenditure when formulating the AMP, UE balances three sets of requirements:

1. Customer requirements: analyse customer expectations and current performance in delivering to those requirements.

2. Technical requirements: a range of inputs drive the technical network requirements that need to be adhered to, including:

– Network performance, asset maintenance and replacement programs: Driven by analysis of fault/performance/cost data and based on reliability centred maintenance analysis

Strategy



– safety compliance: Based on UE’s ESV-approved Electricity Safety Management Scheme which lays out UE’s risk-based approach to managing electrical safety

– capacity planning: Based on probabilistic analysis and contingency planning

– risk analysis: Performed to ISO31000 for significant asset risks

3. Economic requirements: All projects are subject to an appropriate level of economic analysis in accordance with regulatory requirements and prudent investment tests.

9.1.4 Works Program

The Works Program draws on the AMP to develop a more specific 1-2 year picture. The Works Program details specific planned investments in the network, and is used as an input into project planning (development of capital projects), works planning (for small capex and opex), as well as annual budgets.

Projects are sequenced in such a way that they are targeted for completion at a time when they will deliver the best outcomes for the business and its customers.

Programmed asset replacement projects are scheduled to be performed in accordance with replacement policies and as close to, but before, in-service failure.

Demand projects are completed to ensure that sufficient network capacity is in place to meet forecast loads immediately prior to the critical summer loading period.

9.1.5 Works planning and execution

With the investment and asset management plans established, UE then delivers these plans in the most prudent and efficient manner. The key elements to achieve this are:

competitive tendering for capital work activities;

use of approved materials schedules to deliver streamlined purchasing practices; and

use of larger longer-term contracts for works involving ongoing programs of a repetitive nature.

This is achieved through three mechanisms:

1. Long-term prime contracts

UE has long-term contracts (OMSAs) in place with two regional service providers: Zinfra and Downer. Each of these service providers carries out routine maintenance and small capex construction activities within their regional zone under a performance incentive based contract.

2. Projects to tender

For capital works in addition to the regular contracted work, UE has the ability to access OMSA contractors or go to market and ask various parties to tender for the work. This could be either the existing regional service providers, or in some cases new service providers. To help facilitate this process, the Works Program packages up projects to enable benefits to be obtained through tendering significant sized projects. Projects that are suitable to be tendered as turn-key projects are identified at conception stage and a detailed scope of works is prepared as the basis for tender documents.

Strategy



3. Approved materials schedules

United Energy has developed and maintains schedules of materials approved for installation on the network with which all contractors must comply as part of its Health, Safety and Environment systems. This ensures that the integrity of the network assets is maintained and that purchasing and stockholding procedures are streamlined.

In identifying the materials to be used by United Energy a number of factors are used to evaluate the viability of these materials. One of these criterions is distribution electrical losses. This is one of the criteria used in the evaluation of new transformers.

9.2 Asset replacement programme

9.2.1 Summary of planned replacement projects

The table below summarises the planned investments that are to address asset replacement or

refurbishment needs over the next five years.57 The sequence and timing of these projects may

change subject to updated asset information, realignment of other network projects or re-

prioritisation of options to mitigate the deteriorating condition of the assets.

Table 37 – Proposed asset replacement / refurbishment programme

Project description Indicative Timing58

Dandenong South (DSH) - Transformer replacement 2017 - 18

HV Aerial Bundling Cable replacement 2017 – 19

Doncaster (DC) - Pillar replacement 2017 – 20

Heatherton (HT) - Transformer replacement 2017 – 18

Dandenong (DN) - Transformer #1 replacement 2017 - 18

Mulgrave (MGE) - Aged Relays (general replacement) 2017 - 18

Oakleigh East (OE) - Aged relay replacement 2017 – 18

Springvale South (SS) - Aged relay replacement 2017 – 18

Glen Waverley (GW) - Aged relay replacement 2018 - 19

Glen Waverley (GW) - 22kV Switchyard 2018 - 19

Box Hill (BH) - Aged relay replacement 2018 – 19

Carrum (CRM) - 22kV Switchyard 2019 - 20

Carrum (CRM) - Aged relay replacement 2019 - 20

Surrey Hills (SH) - Transformer replacement 2019 – 20

Burwood (BW) – Transformer #3 replacement 2019 – 20

Gardiner (K) - Switchboard replacement 2019 – 20

Gardiner (K) - Aged relay replacement 2019 – 20

57 The programme includes investments with an estimated capital cost of more than $2 million. 58 The timing of asset replacement / refurbishment program is preliminary only based on current assessment and is subject to confirmation by January 2017

Strategy



Project description Indicative Timing58

Bulleen (BU) - Switchboard replacement 2019 –20

Bulleen (BU) - Aged relay replacement 2019 –20

Lyndale (LD) - Transformer replacement 2020 - 21

Frankston South (FSH) - Transformer #1 replacement 2020 - 21

Notting Hill (NO) - Transformer replacement 2020 - 21

Springvale (SV) - 22kV Switchyard replacement 2020 – 21

9.2.2 Impact on network limitations

UE has identified a number of network limitations in Section 6.9.1 which can also be addressed by replacing assets that are reaching their end of economic life with modern like-for-like equivalent or with higher capacity to meet future requirements. UE therefore can take advantage of synergies with asset replacement programme, to address capacity limitations, as highlighted by the projects below:

Replace Dandenong South (DSH) transformers.

Replace North Brighton (NB) 11 kV switchboard and circuit breakers.

It should be noted that the magnitude of expected energy at risk presented in Section 6.9 is based on average unavailability of zone substation transformers and sub-transmission lines. Given a number of zone substation transformers and switchboards are proposed to be replaced due to deteriorating condition of those assets, the magnitude of expected energy at risk would be marginally higher than the values presented in Section 6.9.1.

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10 Metering and Information Technology

10.1 Advance Metering Infrastructure

10.1.1 Overview

In early 2006, the Victorian Government formally endorsed the deployment of Advanced Metering Infrastructure (AMI) to all Victorian electricity customers who use less than 160 MWh per annum. AMI meters, otherwise known as ‘smart meters’ measure energy consumption in half-hour intervals as opposed to the existing meters which measure consumptions on an accumulated basis. Smart meters are read remotely via a purpose-built data communications network which also provides a mechanism for remote customer connection and disconnection.

Smart meters enable customers to exercise choice in their energy management by providing accurate and detailed information about their electricity consumption. Using a web portal (https://energyeasy.ue.com.au/), householders and businesses are able to access accurate and more detailed information about their electricity use. These meters also have the added benefits of:

Enabling embedded generation such as roof-top solar PV to feed electricity back into the distribution system;

Improving supply restoration since the source of the power outage can be pinpointed in real-time;

Providing increased customer service by keeping customers informed of power outages quickly and more accurately;

Remotely controlled re-energisation and de-energisation;

Limited power quality monitoring capability; and

Demand response signalling capability.

The Victorian Government established a legal and regulatory framework, in the Cost Recovery Order in Council (CROIC), for the Victorian distribution businesses to roll out the smart meters to all small customers. In addition, a functionality and service level Order in Council (OIC) was established to place a condition in the Distribution Licence to require the deployment of AMI in accordance with the minimum specified functionality, system performance and service levels.

In December 2011, the Victorian Government re-confirmed its support for AMI to be deployed to all required customers by 31 December 2013. In December 2013, the Victorian Government extended the roll out by a further 6 month to 30 June 2014.

The costs for the installation and operation of the smart meters were previously regulated under an 'Order in Council'. This meant cost recovery for these services was separate to the network charges derived from our revenue determination processes.

https://energyeasy.ue.com.au/

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The smart meter rollout is now largely completed so the UE Metering Services entered a ‘business-as-usual’ phase.

As part of Australian Electricity Regulator Price control decision for the period 2016 to 2020, a portion of Metering costs (68 percent) have been allocated to Standard Control Services (SCS) because some of the IT systems, for example, customer information and billing systems, support network services.

10.1.1.1 AMI programme

The Government mandate required UE to:

Deploy AMI Meters for all residential and small business customers using up to 160 MWh of electricity per annum.

Implement a large-scale, high-performance, two-way data communications network.

Implement new processes and new information systems to capture data at half hourly intervals (48 reads per meter per day).

Integrate new information systems to validate process and store metering data.

Employ business processes to ensure that the current manual meter-reading, back-office environment and current IT systems can be efficiently and effectively operated over the period in which they are being replaced by UE’s AMI programme.

10.1.2 AMI solution

UE’s AMI programme undertook a comprehensive technology and process evaluation to select the technology and processes best able to achieve the mandated AMI obligations with a balance of cost and risk to timely AMI deployment. The AMI solution is shown below.

Figure 147 – UE’s AMI solution

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The UE AMI programme selected mesh radio to deliver the local area meter communications. This technology selection is consistent with:

The stated technology paths of other Victorian distribution businesses, and

The technology choices of other leading AMI programmes across the world.

Information systems are based on purchased software and leading systems integration companies were involved in the implementation.

Our Advanced Metering Infrastructure (AMI) roll-out has been delivered on time and we have installed more than 655,000 AMI meters in our network. We are already realising network benefits from the AMI metering program and will continue to do so. These network benefits provide long term benefits to our customers.

10.1.3 Meter contestability

On 26 November 2015, the AEMC made a final rule that will open up competition in metering services and will give consumers more opportunities to access a wider range of services.

The final rule was made in response to a rule change request from the Council of Australian Governments’ (COAG) Energy Council.

The new arrangements have required changes to the National Electricity Rules (NER) and National Energy Retail Rules (NERR). Key features of the final rule are summarised below.

Providing for the role and responsibilities of the existing “Responsible Person” to be provided by a new type of Registered Participant – a Metering Coordinator; - allowing any person to become a Metering Coordinator, subject to meeting the registration requirements, other than at transmission connection points and in relation to type 7 metering installations; - permitting large customers and Non-Market and exempt Generators to appoint their own Metering Coordinator at distribution connection points; and - requiring a retailer to appoint the Metering Coordinator, except where another has appointed its own Metering Coordinator.

It requires a Metering Coordinator to take on roles additional to those currently performed by the Responsible Person so that the security of, and access to, advanced meters and the services they provide are appropriately managed.

It specifies the minimum services that a new or replacement meter installed at a small customer’s premises must be capable of providing.

It sets out the circumstances in which small customers may opt out of having a new meter installed at their premises.

It clarifies the entitlement of parties to access energy data and access or receive metering data to reflect the changes to roles and responsibilities of parties providing metering services.

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It provides for LNSPs to continue to get the benefit of network devices installed at customers’ premises that allow them to monitor, operate or control their networks for the purpose of providing network services, provided there is sufficient space to house both the metering installation and the network device.

It permits a retailer to arrange for a Metering Coordinator to remotely disconnect or reconnect a small customer’s premises in specified circumstances.

It permits a retailer to arrange for a supply interruption at its customers' premises for the purposes of installing, maintaining, repairing or replacing an electricity meter.

It allows retailer to arrange the de-energisation of a premises if the customer fails to give safe and unhindered access to the premises for the retailer to carry out its responsibilities with regard to metering, subject to certain requirements.

It makes changes to the model terms and conditions of standard retail contracts and deemed standard connection contracts to reflect the changes to the roles and responsibilities of parties providing metering services.

The competitive framework is designed to promote innovation and lead to investment in advanced meters that deliver services valued by consumers at a price they are willing to pay. According to the legislation this new arrangements will commence from 1 December 201759. After this date UE will not be installing any new electricity meters. UE will be responsible for ongoing maintenance of existing electricity meters until they complete end of life or Retailer/Customer choose to upgrade site by paying an exit fee approved by AER as part of EDPR review.

10.1.4 Investment in metering

Table 38 provides UE’s investment in metering which occurred in 2016 and planned investments in metering over the next five years.60

Table 38 – Financial summary of capital investment in metering ($, 000)

2016 2017 2018 2019 2020 2021

Metering 3,026 1,383 12 13 14 14

Information technology 3,371 3,782 538 479 1,461 1,405

AMI Communication 159 151 0 0 0 0

The capital estimates for 2017 to 2021 is based on the EDPR capex approved as per AER final determination in May 201661.

59 UE has submitted a request to AER for an extension in this implementation date. 60 Investments are provided on financial year basis. 61 UE EDPR determination 2016-20 - http://aer.gov.au/networks-pipelines/determinations-access-arrangements/united-energy-determination-2016-20

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10.2 Information Technology Systems

10.2.1 Investment in IT Systems in 2015-16

The following table details the investments that UE has undertaken in IT Systems in 2015-16.

Project Name Year(s) Description

Manage Stakeholders

Application Change Requests (Factory)

2016

Addresses necessary minor changes to UE’s core business applications. The changes include mandatory changes such as Australian Energy Market Operator (AEMO) procedures and other necessary business changes.

Public Website Redesign 2016 Redevelopment of the Public Website to maintain this capability on a supported platform.

Manage Network

SCADA system 2016 Implementation of a new SCADA system to replace the legacy SCADA system which has reached end of life.

Manage Assets

Geographical Information System (GIS) Project

2016 Complete a lifecycle upgrade of the Geographical Information System (GIS) and installation of new infrastructure.

Asset Inspection Mobility Solution

2016 Upgrade the existing mobility solution for asset inspection which has reached end of life.

Vegetation Management System

2016 Provisioning of UE’s own system to manage vegetation inspection and cutting process, which allow for mobile data capture and vegetation history storage.

Enterprise Project and Portfolio Management

2016

Implementation of Project Portfolio Management capability for asset management projects

Implementation of an integrated enterprise project management solution to manage the development and monitoring of its long and short term CAPEX and OPEX programs of work. This includes supporting the development of future EDPR and GAAR submissions across Asset Management, Customer Services and IT.

Manage Meter Data & Revenue

Legacy Meter Systems Rationalisation Project

2016

This project aims to rationalise UE’s customer and meter data management systems by extending the capabilities of the existing AMI platform. This will provide for the consolidation of all meter and customer data. The existing legacy systems can then be decommissioned.

Manage Information Technology

IT Infrastructure Refresh 2016 Lifecycle refresh of UE’s storage, servers, data network, security, data centre hardware and operating level software.

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10.2.2 Investment in IT Systems over the forward planning period 2017-2021

IT Projects mentioned below highlights the future investment UE has planned in IT Systems over the next 5-year planning horizon.

Project Name Year Description

Manage Stakeholders

Application Change Requests (Factory)

2017 – 2021

Addresses necessary minor changes to UE’s core business applications. The changes include mandatory changes such as Australian Energy Market Operator (AEMO) procedures and other necessary business changes.

Power of Choice – Metering Competition

2018 This project provides the enabling technology to support the introduction of Power of Choice reforms for metering competition and related services.

Power of Choice - Consumer Data Access

2017

The Consumer Data Access project provides the capabilities to allow consumers to obtain their energy usage information and allow them to provide explicit and informed consent allowing third parties to access this information on their behalf.

Digital Channel (was Portal Solution)

2017 Provides customers access to information and ability to request and monitor the provision of UE services.

Manage Network

SCADA Refresh 2017 - 2020 Lifecycle refresh of the SCADA platform including a minor refresh in 2017 and a major refresh in 2019.

Distribution Management System (DMS) Refresh

2017 – 2020 Lifecycle refresh of DMS used to maintain network reliability and control the network.

SEMS Refresh 2017 Refresh of Secondary Equipment Management System used to update and record configuration setting of primary protection equipment deployed in the field.

Distribution Management System - LV Management

2019 - 2020 This project extends DMS’s capability to the Low Voltage Network from the current monitor and control of only the High Voltage distribution network.

Outage Management System Upgrade

2018 Provision of enhanced integration with smart meters to improve customer service during outages.

Network Analytics 2017 - 2020 Implementation of improved analysis of real-time data to proactively optimise asset utilisation and identify energy theft.

Works Planning 2017 Implementation of improved works scheduling capability providing a single view of work and visibility of current status across multiple external Service Providers.

Fault Dispatch 2017 Implementation of resource management and field mobility solution to manage the dispatch and field completion of unplanned network faults.

Manage Assets

Geographical Information System (GIS) Refresh

2020 Complete a lifecycle upgrade of the GIS.

Small Applications Lifecycle Refresh

2017 – 2021 On-going program to maintain the currency of approximately 40 small applications.

Asset Data Collection 2018 Extends the ability for service providers to capture asset data in

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Project Name Year Description

the field (for a greater range of assets) on behalf of UE using mobile technology as part of inspection activities or network events.

Asset Management System Capability

2018 – 2020 A program of works aimed at improving and taking advantage of, existing capabilities in ERP and other related applications.

Manage Meter Data and Revenue

Meter Management and Communication Systems Refresh

2017 – 2020 Lifecycle refresh for the software system that supports the smart meter network.

Meter Data Management System Refresh

2017 – 2020 Lifecycle refresh of UE’s Meter Data Management software in 2016 and 2019.

Manage Information Technology

IT Infrastructure Refresh 2019 – 2021 This program is ongoing performing a lifecycle refresh of Storage, Servers, Data Network, security and data centre hardware and operating level software.

Data Protection Refresh 2017 Refresh current technology (hardware & Software) platform for back-ups.

Client Device Lifecycle Refresh

2017 – 2021 Lifecycle refresh of Desktop / Notebook assets.

IT Security Program 2017 – 2021 Program of Security initiatives and deployment of Security tools to address increasing security threats and maintain risk levels.

Manage Information

RIN Reporting Requirements

2017 – 2019 To meet the reporting requirements of the Regulatory Information Notice.

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11 Abbreviations and Glossary

Abbreviations

AEMC Australian Energy Market Commission

AEMO Australian Energy Market Operator

AER Australian Energy Regulator

AMI Advanced Metering Infrastructure

BOM Bureau of Meteorology

DAPR Distribution Annual Planning Report

DNSP Distribution Network Service Provider

DPAR Draft Project Assessment Report

DSE Demand Side Engagement

DSED Demand Side Engagement Document

DSPR Distribution System Planning Report

EDPR Electricity Distribution Price Review

ESV Energy Safe Victoria

EWOV Energy and Water Ombudsman Victoria

FPAR Final Project Assessment Report

LNSP Local Network Service Provider

LTNPQS Long-term National Power Quality Survey

MoU Memorandum of Understanding

NEM National Electricity Market

NER National Electricity Rules

NIEIR National Institute of Economic and Industry Research

NNOR Non-Network Options Report

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NPV Net Present Value

PoE Probability of Exceedance

RIT-D Regulatory Investment Test for Distribution

RIT-T Regulatory Investment Test for Transmission

TCPR Transmission Connection Planning Report

UE United Energy Distribution Pty Ltd

VCR Value of Customer Reliability

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Glossary

1-in-2 peak day The 1-in-2 peak day demand projection has a 50%

probability of exceedance (PoE). This projected level

of demand is expected, on average, to be exceeded

once in two years.

1-in-10 peak day The 1-in-10 peak day demand projection has a 10%

probability of exceedance (PoE). This projected level

of demand is expected, on average, to be exceeded

once in ten years.

Credible option An option that:

Addresses the identified ‘need’;

Is commercially and technically feasible; and

Can be implemented in sufficient time to meet

the identified ‘need’.

Expected Energy at Risk The expected amount of energy that cannot be

supplied each year because there is insufficient

capacity to meet demand, taking into account

equipment unavailability and load-at-risk.

Identified ‘need’ Any capacity or voltage limitation on the distribution

system that will give rise to Expected Energy at Risk.

Limitation Any limitations on the operation of the distribution

system that will give rise to expected energy at risk.

Network option A means by which an identified ‘need’ can be fully or

partly addressed by expenditure on the distribution

asset.

Non-network option A means by which an identified ‘need’ can be fully or

partially addressed other than by a network option.

Non-network service provider A party who provides a non-network option

Potential credible option An option has the potential to be a credible option

based on an initial assessment of the identified ‘need’.

Preferred option A credible option that maximise the present value of net

economic benefit to all those who produce, consume

and transport electricity in the market. The preferred

option can be a network option, non-network option, or

do nothing (i.e. status quo).

Probability of exceedance Refers to the probability that a forecast temperature

condition will occur one or more times in any given year

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and the maximum demand that is expected to

materialise under these temperature conditions. For

example, a forecast 10% probability of exceedance

maximum demand will, on average, be exceeded only 1

year in every 10.

System-normal condition All system components are in-service and configured in

the optimum network configuration.

System-normal limitation A limitation that arises even when all electrical plant is

available for service.

Value of customer reliability The value customer places on having a reliable supply

of energy, which is equivalent to the cost to the

customer of having that supply interrupted expressed in

$/MWh.

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Appendix A – Transmission Connection Planning

Along with the other Victorian DNSPs, UE is required to publish a joint annual transmission connection planning report (TCPR). Jurisdictional regulatory provisions governing the TCPR are set out in clause 3.4 of the Victorian Electricity Distribution Code.

Section 1.3.2 of the 2016 TCPR explains that pursuant to clause 5.13.2(d) of the National Electricity Rules, the TCPR presents the information on transmission connection planning required under schedule 5.8. Section 1.3.2 of the 2016 TCPR contains a table that lists the clauses of schedule 5.8 relating to transmission connection planning information, and provides cross references to the sections of the TCPR where the required information is presented.

The 2016 TCPR is available from United Energy’s website at:


Following table provides summary of risk assessments for UE 11 bulk supply points.

Table 39 – UE Connection point risk assessment summary table

Terminal Station

Indicative timing for completion of preferred network solution (using 2016 VCR)

Expected unserved energy for the year shown in the column to the left (in MWh, and valued at 2016 VCR)

Preferred network solution Indicative annual cost of preferred network solution

Potentially feasible non-network solutions

10th percentile demand forecast


Cranbourne 66 kV (CBTS 66 kV)

2024, in the absence of network support arrangements (or 2022 based on AEMO’s previous VCR estimate escalated to 2016 dollars)

243 MWh in 2024 ($8.67 million)

33.1 MWh in 2024 ($1.18 million)

Install a fourth transformer.

$2 million Demand reduction; Local Generation

Recent reductions in demand forecasts for CBTS have enabled AusNet Electricity Services and United Energy to suspend negotiations with a proponent of network support arrangements. Network support would enable deferral of augmentation


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Terminal Station







East Rowville (ERTS)

No augmentation of capacity is expected to be required within the ten year planning horizon.

Frankston (FTS) No augmentation of capacity is expected to be required within the ten year planning horizon.

Heatherton (HTS) Not before 2026 0.8 MWh ($28,000)

0.1 MWh ($2,300)

Establish a new 220/66 kV terminal station in Dandenong. This option alleviates a number of emerging transmission, connection asset and sub-transmission limitations including at HTS.

$7 million Demand reduction; Local Generation

Malvern 22 kV (MTS 22 kV)


Malvern 66 kV (MTS 66 kV)


Richmond 66 kV (RTS 66 kV)

By summer 2019/20

14.6 MWh in 2017 ($0.22 million)

1.7 MWh in 2017 ($0.07 million)

Permanently transfer load away to the proposed BTS 66 kV station after it is commissioned in late 2016.

The establishment of the BTS 66 kV station is committed and underway.

The establishment of the BTS 66 kV station is committed and underway.

Ringwood 22 kV (RWTS 22 kV)


Ringwood 66 kV (RWTS 66 kV)


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Terminal Station







Springvale (SVTS)

Not before 2026 0.1 MWh ($4,500)

Nil Establish a new terminal station in the Dandenong area to off-load SVTS.

$7 million Demand reduction; Local generation

Templestowe (TSTS)

Not before 2026 0.2 MWh ($6,700)

Nil Install a fourth 150 MVA 220/66 kV transformer at TSTS.

$2 million Demand reduction; Local generation

Tyabb (TBTS) No augmentation of capacity is expected to be required within the ten year planning horizon.

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Appendix B – NER Schedule Cross-References

Schedule 5.8 clause Matters addressed Section No.

5.8(a)

Information regarding the Distribution Network Service Provider and its network

5.8(a)(1) Description of its network Section 4.1

5.8(a)(2) Description of its operating environment Section 4.4

5.8(a)(3) The number and types of its distribution assets Section 4.3

5.8(a)(4) Methodologies used in preparing the DAPR including methodologies used to identify system limitations and any assumptions applied

Section 6.1 Section 6.2 Section 6.3 Section 6.4

5.8(a)(5) Analysis and explanation of any aspects of forecasts and information provided in the DAPR that have changed significantly from previous forecasts and information provided in the preceding year

Section 3.3

5.8(b)

Forecasts for the forward planning period

5.8(b)(1) Description of the forecasting methodology used, sources of input information, and the assumptions applied

Section 5.1 Section 5.2

5.8(b)(2) Load forecasts

At the transmission-distribution connection points including where applicable:

o Total capacity

o Firm delivery capacity for summer periods and winter periods

o Peak Load (summer or winter and an estimate of the number of hours per year that 95% of peak load is expected to be reached)

o Power factor at time of peak load

o Load transfer capacities

o Generation capacity of known embedded generating units

Appendix A (2016 TCPR)

5.8(b)(2) For sub-transmission lines including where applicable:

o Total capacity






Section 6.9.2

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5.8(b)

Forecasts for the forward planning period

5.8(b)(2) For zone substation including where applicable:

o Total capacity






Section 6.9.1

5.8(b)(3) Forecasts of future transmission-distribution connection points (and any associated connection assets), including for each future transmission-distribution connection point:

o Location

o Future loading level

o Proposed commissioning time


5.8(b)(3) Forecasts of future sub-transmission systems and zone substations, including:

o Location

o Future loading level

o Proposed commissioning time

Section 6.9.1

Section 6.9.2

5.8(b)(4) Forecasts of the Distribution Network Service Provider's performance against any reliability targets in a service target performance incentive scheme.

Section 8.1.6

5.8(b)(5) Description of any factors that may have a material impact on its network, including factors affecting:

Fault levels

Voltage levels

Other power system security requirements

The quality of supply to other Network Users (where relevant)

Ageing and potentially unreliable assets

Section 4.4.2

Section 4.4.3

Section 4.4.4

Section 4.4.5

Section 4.4.6

Section 4.4.7

5.8(c)

Information on system limitations for sub-transmission lines and zone substations

5.8(c)(1) Estimates of the location and timing (month(s) and year) of the system limitation

Section 6.9.1

Section 6.9.2

5.8(c)(2) Analysis of any potential for load transfer capacity between supply points that may decrease the impact of the system limitation or defer the requirement for investment

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5.8(c)

Information on system limitations for sub-transmission lines and zone substations

5.8(c)(3) Impact of the system limitation, if any, on the capacity at transmission-distribution connection points

Section 6.9.1

Section 6.9.2

5.8(c)(4) A brief discussion of the types of potential solutions that may address the system limitation in the forward planning period, if a solution is required

5.8(c)(5) Where an estimated reduction in forecast load would defer a forecast system limitation for a period of at least 12 months, include:

An estimate of the month and year in which a system limitation is forecast to occur as required under subparagraph (1)

The relevant connection points at which the estimated reduction in forecast load may occur

The estimated reduction in forecast load in MW or improvements in power factor needed to defer the forecast system limitation

5.8(d)

For any primary distribution feeders for which a Distribution Network Service Provider has prepared forecasts of maximum demands under clause 5.13.1(d)(1)(iii) and which are currently experiencing an overload, or are forecast to experience an overload in the next two years the Distribution Network Service Provider must set out

5.8(d)(1) The location of the primary distribution feeder Section 6.9.3

5.8(d)(2) The extent to which load exceeds, or is forecast to exceed, 100% (or lower utilisation factor, as appropriate) of the normal cyclic rating under normal conditions (in summer periods or winter periods)

5.8(d)(3) The types of potential solutions that may address the overload or forecast overload

5.8(d)(4) Where an estimated reduction in forecast load would defer a forecast overload for a period of 12 months, include:

Estimate of the month and year in which the overload is forecast to occur.

A summary of the locations where relevant connection points at which the estimated reduction in forecast load would defer the overload

The estimated reduction in forecast load in MW needed to defer the forecast system limitation.

5.8(e)

A high-level summary of each RIT-D project for which the regulatory investment test for distribution has been completed in the preceding year or is in progress including:

5.8(e)(1) If the regulatory investment test for distribution is in progress, the current stage in the process.

Section 6.6.1

5.8(e)(2) A brief description of the identified need.

5.8(e)(3) A list of the credible options assessed or being assessed (to the extent reasonably practicable).

5.8(e)(4) If the regulatory investment test for distribution has been completed a brief description of the conclusion, including:

The net economic benefit of each credible option.

The estimated capital cost of the preferred option.

The estimated construction timetable and commissioning date of the preferred option.

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5.8(e)

A high-level summary of each RIT-D project for which the regulatory investment test for distribution has been completed in the preceding year or is in progress including:

5.8(e)(5) Any impacts on Network Users, including any potential material impacts on connection charges and distribution use of system charges that have been estimated.

Section 6.6.1

5.8(f)

Upcoming RIT-D assessments

5.8(f) For each identified system limitation which a Distribution Network Service Provider has determined will require a regulatory investment test for distribution, provide an estimate of the month and year when the test is expected to commence.

Executive summary

5.8(g)

A summary of all committed investments to be carried out within the forward planning period with an estimated capital cost of $2 million or more (as varied by a cost threshold determination) that are to address

5.8(g)(1) A refurbishment or replacement need. Section 9.2

5.8(g)(2) An urgent and unforeseen network issue as described in clause 5.17.3(a)(1), including:

A brief description of the investment, including its purpose, its location, the estimated capital cost of the investment and an estimate of the date (month and year) the investment is expected to become operational.

A brief description of the alternative options considered by the Distribution Network Service Provider in deciding on the preferred investment, including an explanation of the ranking of these options to the committed project. Alternative options could include, but are not limited to, generation options, demand side options, and options involving other distribution or transmission networks.

Section 6.8

5.8(h)

The results of any joint planning undertaken with a Transmission Network Service Provider in the preceding year

5.8(h)(1) A summary of the process and methodology used by the Distribution Network Service Provider and relevant Transmission Network Service Providers to undertake joint planning.


5.8(h)(2) A brief description of any investments that have been planned through this process, including the estimated capital costs of the investment and an estimate of the timing (month and year) of the investment.

5.8(h)(3) Where additional information on the investments may be obtained.

5.8(i)

The results of any joint planning undertaken with other Distribution Network Service Providers in the preceding year

5.8(i)(1) A summary of the process and methodology used by the Distribution Network Service Providers to undertake joint planning.

Section 3.2 Section 6.1 Section 6.2

5.8(i)(2) A brief description of any investments that have been planned through this process, including the estimated capital cost of the investment and an estimate of the timing (month and year) of the investment.

Section 6.7

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5.8(i)

The results of any joint planning undertaken with other Distribution Network Service Providers in the preceding year

5.8(i)(3) Where additional information on the investments may be obtained.

Section 6.7

5.8(j)

Information on the performance of the Distribution Network Service Provider’s network, including

5.8(j)(1) A summary description of reliability measures and standards in applicable regulatory instruments.

Section 8.1.1

5.8(j)(2) A summary description of the quality of supply standards that applies, including the relevant codes, standards and guidelines.

Section 8.2.2

5.8(j)(3) A summary description of the performance of the distribution network against the measures and standards described under subparagraphs (1) and (2) for the preceding year.

Section 8.1.2

Section 8.2.3

5.8(j)(4) Where the measures and standards described under subparagraphs (1) and (2) were not met in the preceding year, information on the corrective action taken or planned.

Section 8.1.4

Section 8.2.4

5.8(j)(5) A summary description of the Distribution Network Service Provider's processes to ensure compliance with the measures and standards described under subparagraphs (1) and (2).

Section 8.1.3

Section 8.2.1

5.8(j)(6) An outline of the information contained in the Distribution Network Service Provider's most recent submission to the AER under the service target performance incentive scheme.

Section 8.1.5

5.8(k)

Information on the Distribution Network Service Provider’s asset management approach, including

5.8(k)(1) A summary of any asset management strategy employed by the Distribution Network Service Provider.

Section 9.1

5.8(k)(1A) An explanation of how the Distribution Network Service Provider takes into account the cost of distribution losses when developing and implementing its asset management and investment strategy.

Section 6.2.2

Section 9.1.3

5.8(k)(2) A summary of any issues that may impact on the system limitations identified in the Distribution Annual Planning Report that has been identified through carrying out asset management.

Section 9.2.2

5.8(k)(3) Information about where further information on the asset management strategy and methodology adopted by the Distribution Network Service Provider may be obtained.

Executive summary

5.8(l)

Information on the Distribution Network Service Provider’s demand management activities, including:

5.8(l)(1)(i) A qualitative summary of:

Non-network options that have been considered in the past year, including generation and embedded generation units;

Section 7.1

Section 7.2

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5.8(l)

Information on the Distribution Network Service Provider’s demand management activities, including:

5.8(l)(1)(ii) A qualitative summary of:

Key issues arising from applications to connect embedded generation units received in the past year

Section 7.5.1

5.8(l)(1)(iii) A qualitative summary of:

Actions taken to promote non-network proposals in the preceding year, including generation from embedded generation units

Section 7.3

5.8(l)(1)(iv) A qualitative summary of:

The Distribution Network Service Provider’s plan for demand management and generation from embedded generation units over the forward planning period

Section 7.4

5.8(l)(2) A quantitative summary of: Connection enquiries received under clause 5.3A.5 Applications to connect received under clause 5.3A.9 The average time taken to complete application to connect

Section 7.5.2

5.8(m)

Metering or IT systems

5.8(m) Information on the Distribution Network Service Provider’s investments in metering or information technology systems which occurred in the preceding year, and planned investments in metering or information technology systems in the forward planning period

Section 10.1

Section 10.2

5.8(n)

A regional development plan consisting of a map of the Distribution Network Service Provider’s network as a whole, or maps by regions, in accordance with the Distribution Network Service Provider’s planning methodology or as required under any regulatory obligation or requirement, identifying

5.8(n)(1) Sub-transmission lines, zone substations and transmission-distribution connection points

Section 4.3.1

5.8(n)(2) Any system limitations that have been forecast to occur in the forward planning period, including, where they have been identified, overloaded primary distribution feeders

Section 6.5

2016-17 to 2020-21 document ue pl 2209 - united energy · 2017-10-05 · distribution annual...

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