Distribution Annual Planning Report (DAPR) to

Transcription

1 Distribution Annual Planning Report (DAPR) to 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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3 Table of Contents 1 Approval and Document Control 7 2 Executive summary 8 3 Introduction Purpose of the DAPR UE s obligations under the Distribution Planning & Expansion Framework Annual planning review and reporting Demand side engagement Regulatory Investment Tests for Distribution Joint planning Victorian arrangements for transmission connection assets Victorian arrangements for shared distribution assets DAPR structure 20 4 Network overview Overview of United Energy Operating environment Network utilisation and load factor Factors influencing demand Economic growth Population growth Temperature sensitive loads Demand management Distributed generation Weather-corrected maximum demand Annual energy Asset age and condition Changes in climate Regulatory environment Assets covered Description of network assets Terminal stations Sub-transmission systems Zone substations High voltage distribution feeders Distribution substations 38 Review by: 12/2014 Page 2 of 309

4 Low voltage network Service lines Communications network Meters Asset management information systems 38 5 Maximum demand forecast Maximum demand forecast method Forecasting assumptions Actual maximum demand calculations Weather-correction Excluded days Reference temperatures New developments Maximum demand forecast comparison Maximum demand forecast accuracy 46 6 Network development plan Network development planning process Planning standards Reliability and security of supply standards Energy loss reduction standards Key assumptions that drive timing of augmentation Forecast summer maximum demand growth Value of Customer Reliability Plant forced outage rates and durations Plant thermal ratings Discount rates Committed projects Forecast distribution network limitations overview Summary of Regulatory Investment Test for Distribution undertaken Summary of joint planning outcomes Summary of projects to address urgent and unforeseen network issues Forecast distribution network limitations Zone substations Box Hill zone substation Beaumaris zone substation Bentleigh zone substation 66 Review by: 12/2014 Page 3 of 309

5 Bulleen zone substation Burwood zone substation Clarinda zone substation Caulfield zone substation Cheltenham zone substation Carrum zone substation Doncaster zone substation Dromana zone substation Dandenong zone substation Dandenong South zone substation Dandenong Valley zone substation East Burwood zone substation Elsternwick zone substation East Malvern zone substation Elwood zone substation Frankston South zone substation Frankston zone substation Glen Waverley zone substation Hastings zone substation Heatherton zone substation Gardiner zone substation Keysborough zone substation Lyndale zone substation Langwarrin zone substation Mentone zone substation Mordialloc zone substation Mulgrave zone substation Moorabbin zone substation Mornington zone substation North Brighton zone substation Notting Hill zone substation Noble Park zone substation Nunawading zone substation Oakleigh zone substation Oakleigh East zone substation Ormond zone substation 166 Review by: 12/2014 Page 4 of 309

6 Rosebud zone substation Surrey Hills zone substation Sandringham zone substation Springvale South zone substation Sorrento zone substation Springvale and Springvale West zone substations West Doncaster zone substation Sub-transmission systems CBTS sub-transmission system ERTS sub-transmission systems HTS sub-transmission systems MTS sub-transmission systems RTS sub-transmission systems RWTS sub-transmission system SVTS sub-transmission systems TBTS sub-transmission systems TSTS sub-transmission systems Distribution feeders Demand side management Current initiatives and projects Doncaster Hill District Energy Services Scheme Virtual Power Plant trial Network performance Network reliability Reliability performance indicators Reliability performance targets Reliability performance UE reliability performance review process Network improvement initiatives Information submitted to the AER Power quality Power quality regulatory requirements Power quality strategy Power quality monitoring capability Power quality analysis Power quality management process 282 Review by: 12/2014 Page 5 of 309

7 8.2.3 Power quality performance Steady state voltage Voltage unbalance Voltage harmonic distortion Voltage sag Other power quality disturbances Power quality initiatives Life cycle asset management planning Asset management strategy Life cycle asset management process Asset design strategy (Conception/Planning/Design) Asset acquisition and building strategy Asset utilisation strategy (Installation/Operation/Maintenance/Repair) Asset disposal strategy Asset replacement programme Summary of planned replacement projects Impact on network limitations Advanced Metering Infrastructure Overview AMI programme AMI solution Investment in metering Abbreviations and Glossary 299 Appendix A Transmission Connection Planning 303 Appendix B NER Schedule Cross-References 304 Review by: 12/2014 Page 6 of 309

8 1 Approval and Document Control Document UE PL 2209 Strategy Distribution Annual Planning Report (DAPR) AUTHOR Name: Roshanth Sivanathan Signature: Title Senior Engineer Network Planning Date SPONSOR Name: Rodney Bray Signature: Title Manager Network Planning Date ENDORSED Name: Craig Savage Signature: Title General Manager Asset Management Date Name: Mike Fajdiga Signature: Title Chief Operating Officer Date Name: Andrew Schille Signature: Title General Manager Regulatory Date Name: Jai McDermott Signature: Title General Manager Corporate Affairs Date VERSION DATE AUTHOR 1 12 th December 2013 UE Network Planning Amendment overview New document Review by: 12/2014 Page 7 of 309

9 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 650,000 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 to This report 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 DAPR provides information on UE s: Distribution network and the environment under which UE operates Asset management approach, and annual planning process, methods and assumptions Maximum demand forecasts including explanations of any significant changes from previous forecasts and its impact on the proposed network development plan Supply risk assessments for UE zone substations, sub-transmission systems and distribution feeders, and for the transmission connection assets Present and emerging network limitations including potential solutions to alleviate the limitations. Network augmentations likely within the planning period are flagged to provide opportunities for interested parties to offer alternative proposals Upcoming Regulatory Investment Test for Distribution (RIT-D) assessments Recent joint planning and demand management activities Recent network performance and improvement programmes Asset replacement/refurbishment, metering and information technology 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 zone substations; 4 sub-transmission systems; and 22 distribution feeders over the following five year planning period as detailed below. 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 parties interested in proposing alternative solutions wanting to seek additional information should direct their enquiries to [email protected]. Review by: 12/2014 Page 8 of 309

10 Summary of major zone substation limitations and augmentation options Limitation Preferred network solution Indicative capital cost ($M) Indicative timing 1 Status Capacity limitation at Dromana (DMA) zone substation. Install a second 66/22 kv 20/33 MVA transformer at DMA zone substation. 8.3 Dec 2015 Identified for RIT-D assessment in the first half of Capacity limitation at Notting Hill (NO), Springvale (SV) and Springvale West (SVW) zone substations. Install a third 66/22 kv 20/33 MVA transformer at NO zone substation and transfer load from SV and SVW zone substations to NO zone substation. 7.0 Dec 2017 Identified for further assessment. 1 The indicative timing in this column shows the month and year in which (in the absence of viable alternatives) UE plans to commission the preferred network solution. This is the time when the annualised cost of power supply interruption to customers is likely to exceed the annualised cost of the network solution. Review by: 12/2014 Page 9 of 309

11 Summary of major sub-transmission system limitations and augmentation options Limitation Preferred network solution Indicative capital cost ($M) Indicative timing 1 Status Capacity limitation on the HTS-MR-BT-NB-HTS sub-transmission system Upgrade the BT-MR 66 kv line and the BT-NB 66 kv line. 0.5 Dec 2014 Identified for further assessment. Capacity limitation on the RTS-EW-SK-RTS sub-transmission system Upgrade droppers on the RTS-EW 66 kv line at EW zone substation. 0.1 Dec 2015 Identified for further assessment. Capacity limitation on the SVTS-EB-RD-SVTS sub-transmission system Upgrade the SVTS-RD 66 kv line (by CitiPower) Upgrade the SVTS-EB 66 kv line (by UE) Dec 2015 Dec 2016 Identified for further assessment. Capacity and voltage limitation in the lower Mornington Peninsula Install new 66 kv line from Hastings (HGS) zone substation to Rosebud (RBD) zone substation Dec 2017 Identified for RIT-D assessment in the second half of Review by: 12/2014 Page 10 of 309

12 Summary of major distribution feeder limitations and augmentation options Limitation Preferred network solution Indicative capital cost ($M) Indicative timing 1 Status Capacity limitation on BH 23 Extend BH 23 by approximately 0.5 km to create a new BH 23 BH 21 tie-line. Once extended, BH 23 will be offloaded onto BH Dec 2014 Identified for further assessment. Capacity limitation on BU 06 Upgrade BU Dec 2014 Identified for further assessment. Capacity limitation on CRM 21 Upgrade CRM Dec 2014 Identified for further assessment. Capacity limitation on CRM 35 Extend CRM 24 by approximately 1.4 km to create a new CRM 24 CRM 35 tie-line. Once extended, CRM 35 will be offloaded onto CRM Dec 2014 Identified for further assessment. Capacity limitation on DN 07 Reconductor LD 07. Once upgraded, DN 07 will be offloaded onto LD Dec 2014 Identified for further assessment. Review by: 12/2014 Page 11 of 309

13 Limitation Preferred network solution Indicative capital cost ($M) Indicative timing 1 Status Capacity limitation on DN 11 Upgrade DN Dec 2014 Identified for further assessment. Capacity limitations on FSH 12 and FSH 33 Upgrade FSH 33. Once upgraded, FSH 12 will be offloaded onto FSH Dec 2014 Identified for further assessment. Capacity limitation on MTN 31 Extend MTN 31 by approximately 0.4 km to create a new MTN 24 MTN 31 tie-line. Once extended, MTN 31 will be offloaded onto MTN Dec 2014 Identified for further assessment. Capacity limitation on MTN 35 Reconductor MTN 22. Once upgraded, MTN 35 will be offloaded onto MTN Dec 2014 Identified for further assessment. Capacity limitation on OAK 23 Upgrade OAK Dec 2014 Identified for further assessment. Capacity limitations on SR 13 and SR 23 Offload SR 13 and SR 23 to adjacent feeders by installing automated switches. 0.3 Dec 2014 Identified for further assessment. Review by: 12/2014 Page 12 of 309

14 Limitation Preferred network solution Indicative capital cost ($M) Indicative timing 1 Status Capacity limitations on BR 01 and BR 09 Upgrade BR 01 feeder exit cable to increase transfer capability. 0.1 Dec 2015 Identified for further assessment. Capacity limitation on CRM 13 Upgrade CRM Dec 2015 Identified for further assessment. Capacity limitation on DVY 24 Establish a new distribution feeder DVY11 from Dandenong Valley (DVY) zone substation. Once commissioned, DVY 24 will be offloaded onto the new distribution feeder. 0.7 Dec 2015 Identified for further assessment. Capacity limitation on FTN 23 Reconductor FTN Dec 2015 Identified for further assessment. Capacity limitations on HGS 22 and HGS 33 Establish a new distribution feeder HGS11 from Hastings (HGS) zone substation. Once commissioned, HGS 22 and HGS 33 will be offloaded onto the new distribution feeder. 0.8 Dec 2015 Identified for further assessment. Capacity limitation on LD 02 Reconductor LD Dec 2015 Identified for further assessment. Review by: 12/2014 Page 13 of 309

15 Limitation Preferred network solution Indicative capital cost ($M) Indicative timing 1 Status Capacity limitations on LD 06 and LD 33 Establish a new distribution feeder LD 34 from Lyndale (LD) zone substation. Once commissioned, LD 06 and LD 33 will be offloaded onto the new distribution feeder. 0.8 Dec 2015 Identified for further assessment. Capacity limitations on MR 22 and MR 24 Establish a new distribution feeder MR 33 from Moorabbin (MR) zone substation. Once commissioned, MR 22 and MR 24 will be offloaded onto the new distribution feeder. 1.2 Dec 2015 Identified for further assessment. Capacity limitation on NB 14 Establish a new distribution feeder EW 05 from Elwood (EW) zone substation. Once commissioned, NB 14 will be offloaded onto the new distribution feeder. 1.7 Dec 2015 Identified for further assessment. Capacity limitations on OR 04, OR 06 and OR 12 Upgrade OR feeders. 0.5 Dec 2015 Identified for further assessment. Capacity limitation on STO 12 Extend RBD 11 to create a new RBD 11 STO 12 tieline. Once extended, STO 12 will be offloaded onto RBD Dec 2016 Identified for further assessment. Review by: 12/2014 Page 14 of 309

16 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 to 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 Distribution network, the operating environment, and the number and type of distribution assets Maximum demand forecasts including explanations of any significant changes from previous forecasts and its impact on the proposed network development plan Asset management approach and annual planning process, methods and assumptions Supply risk assessments of the transmission connection assets, sub-transmission systems, zone substations and high voltage feeders over a minimum five-year planning horizon Present and emerging network limitations including potential solutions to alleviate the limitations. Network augmentations likely within the planning period are flagged to provide opportunities for interested parties to offer alternative proposals Proposed network development plan including upcoming Regulatory Investment Test for Distribution (RIT-D) assessments Joint planning and demand management activities Recent network performance and improvement initiatives Asset replacement/refurbishment, metering and information technology plans. Review by: 12/2014 Page 15 of 309

17 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 applicable to UE s planning activities. This new framework requires UE to prepare and publish annual planning reports, consult with interested parties on possible alternative solutions to address emerging network limitations, undertake joint planning and undertake analysis of proposed network investment using RIT-D 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 of 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 The DAPR can exclude information in relation to transmission connection assets, if it is required under jurisdictional electricity legislation. 2 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 (d) of the NER, information in relation to transmission connection asset planning required under schedule 5.8 is addressed in the 2013 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 2013 TCPR. Table 1 Schedule 5.8 requirements addressed in Transmission Connection Planning Report Schedule 5.8 clause S5.8(a)(4) S5.8(a)(5) S5.8(b)(1) S5.8(b)(2)(i), (iv), (v), (vi), (vii), (viii), and (ix) S5.8(b)(3) Matters addressed A description of the methodology used to identify system limitations. An explanation of any significant changes in demand forecasts from previous forecasts and the impact on the network development plan. A description of the forecasting methodology used. Load forecasts and forecasts of capacity. Forecasts of future transmission-distribution connection points and any associated connection assets. 2 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 to this DAPR. Review by: 12/2014 Page 16 of 309

18 Schedule 5.8 clause S5.8(h) S5.8(n)(2) Matters addressed The results of joint planning undertaken with Transmission Network Service Providers. A map identifying present and emerging transmission connection asset limitations Demand side engagement One of the purposes of the DAPR is to provide information to various stakeholders, including industry participants, customers, interested parties and non-network service providers on present and emerging network limitations. UE s aim is to alleviate network limitations in a manner that maximises the present value of net market benefits. To this end, proponents of non-network solutions for present or emerging network limitations identified in this report are encouraged to contact UE as soon as possible, to ensure that sufficient time is available to fully assess feasible network and non-network solutions. Indicative timeframes for the network solutions are provided in the Executive Summary. UE s Demand Side Engagement Document (DSED) 3 has been developed to outline UE s process for engaging and consulting with non-network service providers, 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 non-network service providers for addressing 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 Provides a real example of UE s non-network engagement. To assist in the assessment of non-network solutions, proponents are invited to make a written submission to UE. All submissions should address all details provided in our DSED. All written submissions or enquiries should be directed to [email protected]. 3 UE: Demand Side Engagement Document. Available at: Review by: 12/2014 Page 17 of 309

19 Alternatively, UE s postal address for enquiries and submissions is: United Energy Attention: Manager Network Planning PO Box 449 Mt Waverley VIC 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. 4 The purpose of the RIT-D is to rank various distribution investment options and identify the credible 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) Publishing a Final Project Assessment Report (FPAR). This DAPR identifies network limitations that require detailed consideration in a RIT-D within the next 12 months to identify the preferred solution to address those limitations (Refer to limitations listed in the Executive Summary) Joint planning 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 (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 4 The purpose, principle and procedures of the RIT-D are set out in NER clause The threshold value is varied from time to time by the Australian Energy Regulator (AER). Review by: 12/2014 Page 18 of 309

20 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 2013 Transmission Connection Planning Report (TCPR), as explained in Appendix A Victorian arrangements for shared distribution assets In accordance with clause 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 CitiPower and SPI Electricity (SPIE). 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. Review by: 12/2014 Page 19 of 309

21 3.3 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. 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. This chapter also provides explanations of any significant changes from previous forecasts and its impact on the proposed network development plan. 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 for sub-transmission systems and zone substations over a minimum five-year planning horizon 5 o Present and emerging network limitations including potential solutions to alleviate those limitations o Proposed network development plan for the planning period including upcoming RIT-D assessments o Joint planning activities undertaken in the last 12 months. Demand management - provides an overview of steps undertaken by UE to promote nonnetwork proposals to alleviate network limitations. 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. Lifecycle asset management planning - 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. Advanced Metering Infrastructure - provides an overview of the AMI rollout programme, including UE s obligations, project status and forecast capital investments in metering. Abbreviations and glossary - provides abbreviations and glossary of terms referred to throughout the DAPR. Appendix A Transmission Connection Planning - presents the transmission connection planning obligations of the DAPR in a document titled 2013 Transmission Connection Planning Report. 5 Details of transmission connection planning are contained in Appendix A of this DAPR. Review by: 12/2014 Page 20 of 309

22 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 650,000 customers throughout Melbourne s south east and the Mornington Peninsula. UE s service area is illustrated below. Figure 1 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 CitiPower and SPI Electricity (SPIE) 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. Review by: 12/2014 Page 21 of 309

23 UE s electricity distribution assets within the service area have a replacement value of over four billion dollars and comprise of 46 zone substations, approximately 205,000 poles, 13,200 distribution substations, 10,200 km of overhead power lines and 2,600 km of underground cables. The actual coincident maximum electricity demand on UE s distribution network for summer was 1982 MW which occurred at 16:00 AEST on 12 March The average ambient temperature of the day was 29.3 C 6 which corresponded to a 77% probability of exceedance (PoE). 7 When weather conditions are taken into account, the weather-corrected 10% PoE maximum demand was 2284 MW. This was higher than the 10% PoE maximum demand projections for , being 2234 MW. Despite the maximum demand result in , the weakening of the Australian economy is forecast to have a dampening effect on UE s maximum demand growth going forward. As such, the average growth in UE s 10% PoE maximum demand for the next 10 years is now forecast to be 1.7 percent per annum, down from last year s forecast of 1.8 percent per annum. By , the 10% PoE maximum demand is projected to increase to 2411 MW. The highest maximum demand experienced to date for the whole of UE s network was 2,084 MW during summer , at an average daily ambient temperature of 35 C corresponding to a 4% PoE. To date, the UE maximum demand has not exceeded this level. UE is continuing to analyse major influences of maximum demand, including economic drivers, climate conditions and any changes to energy usage behaviours as a result of electricity price changes, energy conservation or distributed generation 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. 6 Based on a Melbourne Regional Office maximum daily temperature of 36.2 C and an overnight minimum of 22.3 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 a maximum average temperature that will be 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 a maximum average temperature that will be exceeded, on average, once every two years. In , 10% PoE is defined as a 33.2 C average daily temperature at the Melbourne Regional Weather Station based on 50 years of historical temperature data. The corresponding 50% PoE is 30.1 C and the 90% PoE is 27.9 C. Review by: 12/2014 Page 22 of 309

24 4.2 Operating environment UE operates in an environment where economic growth, population growth and increased penetration of temperature sensitive loads drive 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 Network utilisation and load factor UE s electricity distribution network is augmented based on a probabilistic planning approach where the costs of power supply interruptions, taking into account the probability of plant outages, ratings and demand profiles, is assessed against the annualised cost of a network augmentation. Where 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 cyclic (N- 1) rating for the asset, or in the case of radial assets (i.e. high voltage feeders), the cyclic (N) rating. Figure 2 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 demand 8 to the maximum 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 3. 8 Annual energy purchases divided by 8766 hours per annum. Review by: 12/2014 Page 23 of 309

25 Figure 3 Network load factor 0.65 UE Weather Corrected Load Factor Network 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 Factors influencing demand Economic growth, population growth and increased penetration of temperature sensitive load such as air-conditioning units over the last 15 years have been the major drivers for maximum demand growth in the UE service area. A number of potentially significant emerging developments are occurring or about to occur in the way customers use their electricity. These developments will ultimately have a measurable impact on the maximum demand growth and therefore UE s reinforcement capital expenditure. Increased use of distributed embedded generation through reduced technology cost and increased environmental awareness is already being experienced with roof-top solar photovoltaic panels. These changing drivers of demand and energy are incorporated in UE s annual demand forecast. Therefore, the network limitation assessment and timing of preferred solutions identified in this DAPR reflects the changing environment in which UE operates Economic growth UE engages the National Institute of Economic and Industrial Research (NIEIR) each year to provide the maximum demand forecast for UE s service area. The forecasts are provided by Review by: 12/2014 Page 24 of 309

26 NIEIR on a low, base and high economic growth basis. UE adopts the base economic growth forecast for identifying UE s long term growth capital requirements as this forecast is representative of the expected long term economic growth based on current knowledge. While the high and low economic growth scenarios are useful for assessing the impact of short term changes in the economy on demand, over the long term it is highly unlikely that the economy will continue to maintain successive years of high or low economic growth scenarios Population growth UE s service area population growth is expected to be on average 0.9 percent per annum over the next 10 years with an increase of around 142,000 persons projected. The strongest increase in population over the next 10 years is expected on the Mornington Peninsula with a 1.4 percent per annum growth rate Temperature sensitive loads Over the past decade there has been a trend of divergence between energy and 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 15 years reflecting: The impact of a number of very hot summers (between 1997 and 2010) on discretionary purchases of space cooling equipment Improved marketing penetration and technological advances in space cooling equipment The co-incident 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 The continued ageing of the population and the associated expansion in retirement villages for senior persons. The total temperature sensitive load in the UE s service area has risen from around 390 MW in to over 1,050 MW in Demand management Smart meters currently being 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 Review by: 12/2014 Page 25 of 309

27 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 Distributed generation Over the last several years, an increased use of distributed embedded generation was experienced with roof-top solar photovoltaic panels on 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 microgenerators has a downward influence on UE s growth in maximum demand. This could potentially have an impact on UE s network development plans. Therefore, UE is now incorporating the uptakes of micro-generators into the maximum demand forecasts. 9 During the summer, the UE network had approximately 70 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 was less than 20 MW 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 Historic forecasts and weather-corrected actuals, and forecasts of UE s service area summer maximum demand for the base economic growth scenario is presented below. 9 The uptake of micro-generators is considered by NIEIR in developing the maximum demand forecasts for UE. Review by: 12/2014 Page 26 of 309

28 Figure 4 Maximum demand, base economic growth scenario 10 Growth in UE s maximum demand is expected to be 1.7 percent per annum over the next ten years or 1.6 percent per annum over the next 5 years Annual energy Government energy and climate change policies particularly those encouraging energy efficiency and distributed generation, and the ongoing uncertainty in the global economy is expected to have a significant impact on energy sales growth in the UE service area. It is projected that growth in energy consumption is expected to be around 0.6% per annum for the planning period. Projections of UE s overall annual energy sales for the base economic growth scenario are presented below. 10 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. Review by: 12/2014 Page 27 of 309

29 Figure 5 Annual energy sales, base economic growth scenario Historical Forecast 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 II to accommodate the arrival of the baby boomers and the post-war economic growth. Investment in the network accelerated in the late 1950 s and reached a peak in the decade between 1960 and This network expansion was at a time when the parts of the south eastern suburbs within UE s service area and parts of the Mornington Peninsula were predominantly rural land under development. Much of this area is now urbanised. The present implication is that an increasing number of assets are at end-of-life and require replacement over the current planning period Changes in climate Changes in climate can have an adverse impact on UE s network performance. In recent history, UE has experienced a number of extreme events leading to poor performance of the network, including periods of extreme temperatures and drought and number of severe storms, particularly strong wind events. 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 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). Review by: 12/2014 Page 28 of 309

30 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). Review by: 12/2014 Page 29 of 309

31 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 6). UE s distribution network is predominantly overhead and made up of a large number of interconnected assets of varying age and condition. Figure 6 UE distribution asset portfolio Review by: 12/2014 Page 30 of 309

32 Table 2 provides a breakdown of UE distribution assets as at 31 December Table 2 UE network parameters Network parameters Statistics Network service area 1472 km 2 Peak coincident demand MW Total customers 647,892 Bulk supply points 11 Sub-transmission circuits 78 Zone substations 46 Major power transformers 109 Distribution transformers 13,276 Power poles 205,363 Overhead powerlines - Sub-transmission 638 km - High voltage distribution 3,745 km - Low voltage distribution 5,899 km Underground power cables - Sub-transmission 12 km - High voltage distribution 960 km - Low voltage distribution 1,670 km Description of network assets Terminal stations UE takes bulk supply from the shared transmission network at eleven transmission connection points provided by nine terminal stations at 66kV, two of which also provide supplies at 22kV. 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 SPI PowerNet, however, UE is responsible for planning and directing augmentations to the connection 11 UE: Regulatory Information Notice (RIN). 12 The actual maximum demand recorded on the UE network for summer Review by: 12/2014 Page 31 of 309

33 assets. At seven of the eleven connection points, supply is shared with other distribution businesses and therefore joint planning and risk sharing arrangements exist. Table 3 presents the terminal stations that supply the UE distribution network. Table 3 UE bulk supply points Terminal station Abbreviation Supply voltage Shared supply Cranbourne / Frankston CBTS / FTS 66 kv SPIE East Rowville ERTS 66 kv SPIE Heatherton HTS 66 kv No Malvern MTS 66 kv No Malvern MTS 22 kv No Richmond RTS 66 kv CitiPower Ringwood RWTS 66 kv SPIE Ringwood RWTS 22 kv SPIE Springvale SVTS 66 kv CitiPower Templestowe TSTS 66 kv CitiPower, JEN, SPIE Tyabb TBTS 66 kv No Sub-transmission systems The UE sub-transmission system consists of overhead powerlines 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 4 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 SPIE ERTS-LD-MGE-ERTS 66 kv No HTS-M/MC-BR-HTS 66 kv No HTS-MR-BT-NB-HTS 66 kv No HTS-HT-CM-SR-HTS 66 kv No Review by: 12/2014 Page 32 of 309

34 Sub-transmission system Supply voltage Shared supply 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 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 Zone substations The UE network has a total of 46 zone substations where the voltage is converted from subtransmission 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 5 UE zone substations Zone substation Abbreviation Transformation Shared supply Box Hill BH 66/22 kv No Beaumaris BR 66/11 kv No Review by: 12/2014 Page 33 of 309

35 Zone substation Abbreviation Transformation Shared supply 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 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 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 Review by: 12/2014 Page 34 of 309

36 Zone substation Abbreviation Transformation Shared supply 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 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 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 7 illustrates the location of UE bulk supply points, zone substations and sub-transmission systems. Figure 8 illustrates the geographical area serviced by each zone substation. Review by: 12/2014 Page 35 of 309

37 Figure 7 UE bulk supply points, zone substations and sub-transmission systems (schematic view) Review by: 12/2014 Page 36 of 309

38 Figure 8 UE zone substation supply areas Review by: 12/2014 Page 37 of 309

39 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 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 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 customer s installation interacts with the UE distribution network. Each customer within our service area has a service connection from the overhead or underground low voltage network 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 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 are being rolled out to all customers consuming less than 160 MWh as part of the Advanced Metering Infrastructure (AMI) programme 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). Works Management and Logistics (SAP). Review by: 12/2014 Page 38 of 309

40 SCADA, Outage Management and Distribution Management Systems (OMS/DMS). Network Load Management System (NLM). Document Management. Power quality database. Real-time data historian. Ratings Database. PSSE/PSSU/PSS Sincal power flow simulation. Asset management, models, tools and databases. Review by: 12/2014 Page 39 of 309

41 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 economic growth, population growth, weather patterns, solar photovoltaic panel installations, government energy/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. Given the high dependency of maximum demand on economic conditions and ambient temperature, UE s maximum demand forecasts are developed under three economic conditions 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 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 noncoincident 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 for Victoria and UE supply area. o Government policies which impact on electricity demand and consumption. Review by: 12/2014 Page 40 of 309

42 o The impacts of the roll-out of smart meters, air-conditioning usage, retail electricity prices, electric vehicles 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 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 maximum demand forecasts for the UE service area prepared by NIEIR is compared against the top-down macro-economic maximum demand forecasts developed by UE using the 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. Once reconciled, UE uses the bottom-up forecast for the purpose of planning the network, as this provides detailed information at the asset levels to identify emerging capacity limitations. Review by: 12/2014 Page 41 of 309

43 5.2 Forecasting assumptions 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 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 by adding on the demand that was shed 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 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 year is the most recent year representing a less than 10% PoE demand profile. 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 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. Review by: 12/2014 Page 42 of 309

44 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 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 weather station for , as shown below. Table 6 Average daily temperature at Melbourne Regional Office weather station POE Average daily temperature ( C) 13 Summer 10% % % 28.7 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 summer. 13 Average of the peak day temperature and the previous night s minimum temperature. Review by: 12/2014 Page 43 of 309

45 Table 7 10% PoE average temperatures at Cerberus and Scoresby weather station Location 10% PoE Average daily temperature ( C) Cerberus 31.4 Scoresby 33.4 The average daily temperatures presented above are used to develop the weather-corrected 10% PoE maximum demand forecasts for each zone substation New 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. Review by: 12/2014 Page 44 of 309

46 5.3 Maximum demand forecast comparison Growth in UE s 10% PoE maximum demand is expected to be 1.7% per annum over the next ten years or 1.6% per annum over the next five years. The latest 2013 forecasts are marginally down from last year s forecasts adopted in the 2012 Distribution System Planning Report (DSPR) as highlighted in Figure 9. The reduced forecasts are a reflection of the economic slowdown and therefore slower maximum demand growth. It is noted that under the latest forecasts, maximum demand is still expected to increase over the planning period. Figure 9 UE maximum demand forecasts (MW) The network limitation assessments and timing of network augmentations in this document are based on the latest maximum demand forecast developed during Given the marginal change in the maximum demand forecast compared with last year s forecast, the timing of network augmentations identified in this document is not expected to be significantly different to those published in the 2012 DSPR, but likely to be deferred by one year on average. Given demand growth is not homogeneous across the entire UE distribution network, the timing of each proposed augmentation has been determined on a case-by-case basis. Review by: 12/2014 Page 45 of 309

47 5.4 Maximum demand forecast accuracy Although current maximum demand forecasts show a slower growth rate than has previously been experienced over the last ten years, electricity maximum demand in UE s service area is still projected to continue to grow at 1.7% per annum over the next ten years (1.6% per annum over the next five 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 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 that summer undertaken in the prior year. The results of the weather-corrected actual and the historical (and current) forecast based on a 50% PoE are overlaid in the chart below. Review by: 12/2014 Page 46 of 309

48 Figure 10 UE summer maximum demand (MW) Since 2004, the difference between the forecast and the weather-corrected actual maximum demand has remained within the extremes of -3.6% and +3.2% with an average error over the period of +0.1%. Review by: 12/2014 Page 47 of 309

49 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 ensure customer maximum demand is met under system-normal operation 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. Review by: 12/2014 Page 48 of 309

50 Figure 11 UE distribution network development planning process Process before publishing DAPR Process after publishing DAPR Network historical load records Hold public forum to discuss non-network opportunites Load Forecasting Medium to Long term Calculate plant ratings based on pre-defined standard conditions and load profiles 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 network risk assessment Identify the lead DNSP to develop project No Is the network limitation on the shared distribution system? Undertake RIT-D assessment (if applicable) Develop internal business case Identify potential options Identify potential options though joint planning with UE and other Victorian DNSPs Satisfy RIT-D requirements (if applicable) Do non-network options address network limitations? No Is the value of expected energy at risk greater than the cost to augment the network? Yes Develop Non-Network Project Offer Approve business case Prepare contingency plans Propose network augmentations Notify AEMO as required and provide access standards Prepare pre-contingency measures Determine optimum timing Approve business case Publish Distribution Annual Planning Report Execute Network Support Agreement Plan and implement preferred option(s) Review by: 12/2014 Page 49 of 309

51 6.2 Planning standards 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 failure rates 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. Where 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. In other words, UE absorbs some level of load-at-risk before augmenting the network. 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 ensure that maximum demand can be supplied with all plant in-service for all but one-in-ten years. The probabilistic planning approach is then applied using a suitable combination of 10%, 50% and 90% PoE demand forecasts to ensure 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 in the event of an asset outage. In order to determine the economically optimum level of augmentation, 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) and 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 value 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 a RIT-D, a set of scenarios is applied to test the sensitivity of the economic viability of a 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 quickly as possible. As demand and network utilisation increases over time, the efficacy of contingency plans in terms of managing network Review by: 12/2014 Page 50 of 309

52 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 plants 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 Deployment of relocatable transformers in the event of an emergency 14 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, backed up by a set of appropriate contingency plans, is expected to deliver a satisfactory level of supply security and reliability at an acceptable level of cost to the community 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), and the value of distribution network capacity that is made available when energy losses are reduced (the released capacity benefit). 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. 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 14 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 2 to 4 days. Review by: 12/2014 Page 51 of 309

53 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. Review by: 12/2014 Page 52 of 309

54 6.3 Key assumptions that drive timing of augmentation Forecast summer maximum demand growth Although recent demand forecasts 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 1.7% per annum over the next ten years or 1.6% per annum over the next five years 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). The VCR used by UE to calculate the cost of expected unserved energy is provided by AEMO each year. For the DAPR, it is an updated estimate of the composite (or average) value of customer reliability in Victoria for all electricity customers. Table 8 Value of customer reliability (nominal) VCR ($/kwh) Summary of indexed VCR using OGW methodology 15 Year Residential Agricultural Commercial Industrial Victoria 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. AEMO is currently undertaking a review of the national VCR, with the aim of producing VCRs at the transmission node level to provide sufficient granularity to enhance network investment decision-making process. AEMO aims to publish the VCRs in April To date, the VCR is derived at regional level based on regional customer surveys Source: AEMO 16 The regional VCRs are presently calculated based on surveys from the Residential, Commercial, Agricultural and Industrial and customer sectors. Review by: 12/2014 Page 53 of 309

55 Further information is available from: Reliability-Statement-of-Approach The adoption of the VCRs at transmission nodes may have some impact on the investment decisions outlined in this DAPR. UE intends to adopt the latest VCRs when undertaking detailed analysis in accordance with RIT-D 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 Table 9 Sub-transmission line outage data Major plant item: Sub-transmission lines Interpretation Line failure rate (sustained fault) Duration of outage (sustained fault) 5.1 faults per 100 km per annum The average sustained failure rate of UE s subtransmission lines is 5.1 faults per 100 km per year. 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 ( ) ( ) 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. Table 10 Zone substation transformer outage data Major plant item: zone substation transformer Interpretation Transformer failure rate (major fault) Duration of outage (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 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 ( ) ( ) 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 Review by: 12/2014 Page 54 of 309

56 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 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/m 2 and a wind speed of 3 m/s at an angle to the conductor of 15 (i.e. an effective 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 Discount rates A discount rate currently at 9.5% (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. 6.4 Committed 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 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 11. Table 11 Committed projects Project Expected commissioning date Box Hill (BH) third transformer Jan 2014 Keysborough (KBH) zone substation Dec 2014 Langwarrin (LWN) second transformer Dec 2014 Review by: 12/2014 Page 55 of 309

57 6.5 Forecast distribution network limitations overview Figure 12 shows UE s transmission connection points (bulk supply points), zone substations and sub-transmission systems. It also shows the present and emerging zone substation and sub-transmission system limitations (Refer to Table 12 and Table 13) and RIT-D assessment that UE may conduct in Figure 12 Zone substation and sub-transmission system limitations (schematic view) L4 L5 L2 L3 L6 L1 Review by: 12/2014 Page 56 of 309

58 Figure 13 shows the present and emerging distribution feeder limitations (Refer to Table 14). Figure 13 Distribution feeder limitations L8 L7 L16 L27 L28 L26 L17 L25 L24 L19 L12 L11 L21 L9 L10 L20 L22 L13 L15 L23 L14 L18 Review by: 12/2014 Page 57 of 309

59 Table 12 to Table 14 summarises the forecast distribution network limitations. Table 12 Zone substation limitation summary Limitation Preferred network solution Indicative capital cost ($M) Indicative timing Figure 12 Reference Capacity limitation at Dromana (DMA) zone substation Install a second 66/22 kv 20/33 MVA transformer at DMA zone substation. 8.3 Dec 2015 L1 Capacity limitation at Notting Hill (NO), Springvale (SV) and Springvale West (SVW) zone substations Install a third 66/22 kv 20/30 MVA transformer at NO zone substation and transfer load from GW, SV and SVW zone substations to NO zone substation. 7.0 Dec 2017 L2 Table 13 Sub-transmission system limitation summary Limitation Preferred network solution Indicative capital cost ($M) Indicative timing Figure 12 Reference Capacity limitation on the HTS- MR-BT-NB-HTS subtransmission system Upgrade the BT-MR 66 kv line and the BT-NB 66 kv line. 0.5 Dec 2014 L3 Capacity limitation on the RTS- EW-SK-RTS sub-transmission system Upgrade droppers on the RTS-EW 66 kv line at EW zone substation. The preferred option was identified through joint planning with CitiPower. 0.1 Dec 2015 L4 Capacity limitation on the SVTS- EB-RD-SVTS sub-transmission system Upgrade the SVTS-RD 66 kv line (by CitiPower) Upgrade the SVTS-EB 66 kv line (by UE) The preferred option was identified through joint planning with CitiPower Dec 2015 Dec 2016 L5 Capacity and voltage limitation in the lower Mornington Peninsula Install new 66 kv line from Hastings (HGS) zone substation to Rosebud (RBD) zone substation Dec 2017 L6 Table 14 Distribution feeder limitation summary Limitation Preferred network solution Indicative capital cost ($M) Indicative timing Figure 13 Reference Capacity limitation on BH 23 Extend BH 23 by approximately 0.5 km to create a new BH 23 BH 21 tie-line. Once extended, BH 23 will be offloaded onto BH Dec 2014 L7 Capacity limitation on BU 06 Upgrade BU Dec 2014 L8 Capacity limitation on CRM 21 Upgrade CRM Dec 2014 L9 Capacity limitation on CRM 35 Extend CRM 24 by approximately 1.4 km to create a new CRM 24 CRM 35 tie-line. Once extended, CRM 35 will be offloaded onto CRM Dec 2014 L10 Capacity limitation on DN 07 Reconductor LD 07. Once upgraded, DN 07 will be offloaded onto LD Dec 2014 L11 Capacity limitation on DN 11 Upgrade DN Dec 2014 L12 Capacity limitations on FSH 12 and FSH 33 Upgrade FSH 33. Once upgraded, FSH 12 will be offloaded onto FSH Dec 2014 L13 Capacity limitation on MTN 31 Extend MTN 31 by approximately 0.4 km to create a new MTN 24 MTN 31 tie-line. Once extended, MTN 31 will be offloaded onto MTN Dec 2014 L14 Review by: 12/2014 Page 58 of 309

60 Limitation Preferred network solution Indicative capital cost ($M) Indicative timing Figure 13 Reference Capacity limitation on MTN 35 Reconductor MTN 22. Once upgraded, MTN 35 will be offloaded onto MTN Dec 2014 L15 Capacity limitation on OAK 23 Upgrade OAK Dec 2014 L16 Capacity limitations on SR 13 and SR 23 Offload SR 13 and SR 23 to adjacent feeders by installing automated switches. 0.3 Dec 2014 L17 Capacity limitation on STO 12 Extend RBD 11 to create a new RBD 11 STO 12 tie-line. Once extended, STO 12 will be offloaded onto RBD Dec 2016 L18 Capacity limitations on BR 01 and BR 09 Upgrade BR 01 feeder exit cable to increase transfer capability. 0.1 Dec 2015 L19 Capacity limitation on CRM 13 Upgrade CRM Dec 2015 L20 Capacity limitation on DVY 24 Establish a new distribution feeder from Dandenong Valley (DVY) zone substation. Once commissioned, DVY 24 will be offloaded onto the new distribution feeder. 0.7 Dec 2015 L21 Capacity limitation on FTN 23 Reconductor FTN Dec 2015 L22 Capacity limitations on HGS 22 and HGS 33 Establish a new distribution feeder from Hastings (HGS) zone substation. Once commissioned, HGS 22 and HGS 33 will be offloaded onto the new distribution feeder. 0.8 Dec 2015 L23 Capacity limitation on LD 02 Reconductor LD Dec 2015 L24 Capacity limitations on LD 06 and LD 33 Establish a new distribution feeder from Lyndale (LD) zone substation. Once commissioned, LD 06 and LD 33 will be offloaded onto the new distribution feeder. 0.8 Dec 2015 L25 Capacity limitations on MR 22 and MR 24 Establish a new distribution feeder from Moorabbin (MR) zone substation. Once commissioned, MR 22 and MR 24 will be offloaded onto the new distribution feeder. 1.2 Dec 2015 L26 Capacity limitation on NB 14 Establish a new distribution feeder from Elwood (EW) zone substation. Once commissioned, NB 14 will be offloaded onto the new distribution feeder. 1.7 Dec 2015 L27 Capacity limitations on OR 04, OR 06 and OR 12 Upgrade OR feeders. 0.5 Dec 2015 L28 Review by: 12/2014 Page 59 of 309

61 6.6 Summary of Regulatory Investment Test for Distribution undertaken UE has not commenced nor undertaken any Regulatory Investment Test for Distribution (RIT-D) or any Regulatory Test in Summary of joint planning outcomes In 2012, UE undertook joint planning with CitiPower to alleviate the capacity limitation on the shared SVTS-EB-RD-SVTS 66 kv sub-transmission system. The preferred option was to transfer Riversdale (RD) zone substation, owned and operated by CitiPower, from Springvale Terminal Station (SVTS) to Malvern Terminal Station (MTS). This was to be achieved by: Converting the Burwood (BW) zone substation, owned and operated by UE, from 22 kv to 66 kv Constructing two new 66 kv lines from MTS. In 2013, UE and CitiPower undertook detailed assessment of the preferred option and found that the cost of converting BW zone substation was significantly higher than originally anticipated. The joint planning concluded that under the present maximum demand growth projections, there are other cost-effective solutions that can be implemented to provide a solution to the limitations on this sub-transmission system. 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 (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. Review by: 12/2014 Page 60 of 309

62 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 maximum demand over the next five years to identify current and emerging capacity limitations. The following key data are presented in this section (where appropriate): (N) rating refers to the capability of the zone substation/sub-transmission system/distribution feeder with all plants in-service. Cyclic (N-1) rating refers to the 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. Forecast network maximum demands. Energy-at-risk is the amount of energy that would not be supplied due to a major outage of critical plants for a given demand condition. Expected unserved energy is the portion of the energy at risk after taking into account the probability of major outage of critical plants. Customer value of lost load is the cost of the expected unserved energy, obtained by multiplying the expected unserved energy by the VCR. Power factor is the ratio of the active power to the apparent power. Load transfer capacity is the available capacity within the network to transfer load to adjacent zone substations through the distribution feeder network at time of maximum demand. 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 nonnetwork 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. Review by: 12/2014 Page 61 of 309

63 Load (MVA) Strategy Zone substations Box Hill zone substation Box Hill (BH) zone substation consists of two 20/33 MVA 66/22 kv transformers and supplies the suburbs of Blackburn, Box Hill and the Box Hill Central precinct. UE is installing a third 20/33 MVA 66/22 kv transformer at BH which is expected to be commissioned by January Magnitude, probability and impact of loss of load BH is a summer-critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 14 Forecast maximum demand against station ratings for BH zone substation BH Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating The figure above shows that the demand at BH zone substation has been above its (N-1) rating since summer However, following the installation of the third transformer, the demand at BH zone substation is expected to remain within its (N-1) rating for the next five years. Therefore, no major demand related augmentation is planned at BH zone substation over the next five years. Review by: 12/2014 Page 62 of 309

64 Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. BH zone substation Summer cyclic N Rating (MVA) Summer cyclic N-1 Rating (MVA) 72.6 Embedded generation capacity (MW) 0.0 BH zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 18.1 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 63 of 309

65 Load (MVA) Strategy 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. Magnitude, probability and impact of loss of load BR is a summer-critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 15 Forecast maximum demand against station ratings for BR zone substation BR Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating The demand at BR zone substation is expected to marginally exceed its (N-1) rating from summer However, the expected energy at risk is insignificant over the planning period. Therefore, no major demand related augmentation is planned at BR zone substation over the next five years. Review by: 12/2014 Page 64 of 309

66 Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. BR zone substation Summer cyclic N Rating (MVA) 63.0 Summer cyclic N-1 Rating (MVA) 31.5 Embedded generation capacity (MW) 0.0 BR zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 4.2 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 65 of 309

67 Load (MVA) Strategy 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. Magnitude, probability and impact of loss of load BT is a summer-critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 16 Forecast maximum demand against station ratings for BT zone substation BT Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating The demand at BT zone substation is expected to remain within its (N-1) rating for the next five years. Therefore, no major demand related augmentation is planned at BT zone substation over the next five years. Review by: 12/2014 Page 66 of 309

68 Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. BT zone substation Summer cyclic N Rating (MVA) 62.1 Summer cyclic N-1 Rating (MVA) 31.1 Embedded generation capacity (MW) 0.0 BT zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 7.9 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 67 of 309

69 Load (MVA) Strategy 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. Magnitude, probability and impact of loss of load BU is a summer-critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 17 Forecast maximum demand against station ratings for BU zone substation BU Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating The demand at BU zone substation is expected to exceed its (N-1) rating from summer The figure below depicts the expected energy at risk with one transformer out-of-service for the 10% PoE demand forecast, and the hours per year that the 10% PoE demand is forecast is expected to exceed the (N-1) station rating. The graph also shows the value to customers of the expected unserved energy in each year, for the 10% PoE demand forecast. Review by: 12/2014 Page 68 of 309

70 Expected Energy at Risk above N-1 (kwh) and Hours at Risk above N-1 (hrs) Customer value of lost load ($) Strategy Figure 18 Annual energy, hours at risk and expected customer value of lost load at BU Magnitude of load at risk above (N-1) and value of lost load at BU 70 $4, $4, Year $3,500 $3,000 $2,500 $2,000 $1,500 $1,000 $500 $0 Hours at risk above N-1 Expected energy above N-1 (kwhr) Customer value of lost load ($) 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 summer for about 6 hours. It is emphasised however that the probability of a major outage of one of the transformers occurring over the duration of high load is very low. When the energy at risk is weighted by this low probability, the expected energy at risk is estimated to be 13 kwh in summer If no action is taken, this figure is expected to rise to 63 kwh in summer , with a value to customers of around $4.0k. 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. Contingency plans to transfer load to adjacent zone substations. Plans to transfer load to adjacent zone substations at the distribution feeder level are established. These plans are reviewed annually prior to the summer season. Transfer capability away from BU zone substation is just under 5.3 MVA for summer Establish a new 66/11 kv zone substation. There are no sites presently under consideration to be developed as a new zone substation to offload however there is opportunity to offload BU to the proposed Templestowe (TSE) zone substation by converting 11 kv assets to 22 kv. The timing of this augmentation is expected to be no earlier than December Review by: 12/2014 Page 69 of 309

71 3. Install new transformation at an adjacent zone substation. Install the fourth 66/22 kv transformer at Doncaster (DC) zone substation. Some load from BU can be transferred away from BU by converting 11 kv assets to 22 kv. 4. Install a third 66/11 kv transformer at BU zone substation. Preferred network option(s) for alleviation of limitations Given the expected energy at risk is insufficient to justify augmentation, UE proposes to maintain contingency plans to transfer load quickly to adjacent zone substations for an unplanned outage of a transformer at BU zone substation under critical loading conditions. As a means of managing the risk at BU and DC zone substations, UE may establish a new zone substation at Templestowe (TSE) or augment DC with a fourth transformer (with some subtransmission reinforcement). Once the preferred option is implemented, the distribution feeders shall be used to offload BU. The timing of this augmentation is expected to be no earlier than December Therefore, no major demand related augmentation is planned at BU zone substation over the next five years. Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. BU zone substation Summer cyclic N Rating (MVA) 59.5 Summer cyclic N-1 Rating (MVA) 29.7 Embedded generation capacity (MW) 0.0 BU zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 5.3 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 70 of 309

72 Load (MVA) Strategy Burwood zone substation Burwood (BW) zone substation is fully developed with three 10 MVA 22/11 kv transformers and supplies the suburbs of Ashwood and Burwood. The BW transformers were manufactured in the late 1940s and early 1950s. Given the age and deteriorating condition of the transformers, UE plans to replace BW No.1 and No.2 transformers by December BW No.3 transformer is expected to be replaced by December Magnitude, probability and impact of loss of load BW is a summer-critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 19 Forecast maximum demand against station ratings for BW zone substation BW Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating The demand at BW zone substation is expected to marginally exceed its (N-1) rating from summer However, the expected energy at risk is insignificant over the planning period. Therefore, no major demand related augmentation is planned at BW zone substation over the next five years. Review by: 12/2014 Page 71 of 309

73 Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. BW zone substation Summer cyclic N Rating (MVA) 36.4 Summer cyclic N-1 Rating (MVA) 24.3 Embedded generation capacity (MW) 0.0 BW zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 7.3 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 72 of 309

74 Load (MVA) Strategy 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. CDA zone substation supplies the suburbs of Clarinda and Oakleigh South. Prior to summer , the (N-1) rating at CDA was zero because the station only had a single transformer. CDA was reliant on backup distribution feeder transfer capability 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. Magnitude, probability and impact of loss of load CDA is a summer-critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 20 Forecast maximum demand against station ratings for CDA zone substation CDA Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating The demand at CDA zone substation is expected to exceed its (N-1) rating from summer The figure below depicts the expected energy at risk with one transformer out-of-service for the 10% PoE demand forecast, and the hours per year that the 10% PoE demand is forecast is expected to exceed the (N-1) station rating. The graph also shows the value to customers of the expected unserved energy in each year, for the 10% PoE demand forecast. Review by: 12/2014 Page 73 of 309

75 Expected Energy at Risk above N-1 (kwh) and Hours at Risk above N-1 (hrs) Customer value of lost load ($) Strategy Figure 21 Annual energy, hours at risk and expected customer value of lost load at CDA Magnitude of load at risk above (N-1) and value of lost load at CDA 35 $2, $2, $1, $1, $ Year $0 Hours at risk above N-1 Expected energy above N-1 (kwhr) Customer value of lost load ($) As shown above, if there is a forced transformer outage during summer maximum demand periods, there will be insufficient capacity at CDA zone substation to supply all demand in summer for about 5 hours. It is emphasised however that the probability of a major outage of one of the transformers occurring over the duration of high load is very low. When the energy at risk is weighted by this low probability, the expected energy at risk is estimated to be 12 kwh in summer If no action is taken, this figure is expected to rise to 32 kwh in summer , with a value to customers of around $2k. The relocatable transformer may need to be used at another 66/22 kv zone substation if a major transformer fault occurs at a high risk zone substation. While CDA has manageable capacity to remove the relocatable transformer at any time over the next five years, it would leave CDA with a single transformer rating. 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. Contingency plans to transfer load to adjacent zone substations. Plans to transfer load to adjacent zone substations at the distribution feeder level are established. These plans are reviewed annually prior to the summer season. Transfer capability away from CDA zone substation is assessed at 22.8 MVA for summer Establish a new 66/22 kv zone substation. There are presently no sites under consideration to be developed as a new zone substation to offload CDA. Review by: 12/2014 Page 74 of 309

76 3. Install a second fixed 66/22 kv 20/33 MVA transformer at CDA zone substation. In the absence of any lower-cost options, installation of another transformer at CDA is most likely the least cost technically feasible network option for addressing the limitations at CDA at some time in the future. Preferred network option(s) for alleviation of limitations Given the expected energy at risk is insufficient to justify augmentation, UE proposes to implement contingency plans to transfer load quickly to adjacent zone substations for an unplanned outage of a transformer at CDA under critical loading conditions. Therefore, no major demand related augmentation is planned at CDA zone substation over the next five years. Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. CDA zone substation Summer cyclic N Rating (MVA) 72.5 Summer cyclic N-1 Rating (MVA) 25.8 Embedded generation capacity (MW) 0.0 CDA zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 22.8 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 75 of 309

77 Load (MVA) Strategy 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 built in to replace the former Caulfield (T) 22/11kV zone substation. CFD was also incorporated into the MTS-EM-EL-MTS sub-transmission system to form the MTS-EM-EL-CFD-MTS sub-transmission system as part of the rebuild project. Magnitude, probability and impact of loss of load CFD is a summer-critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 22 Forecast maximum demand against station ratings for CFD zone substation CFD Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating During summer , the maximum demand at CFD zone substation exceeded its (N-1) rating. Given a steady demand growth over the next five years, a significant amount of energy would be at risk in the event of a forced transformer outage during maximum demand periods. The figure below depicts the expected energy at risk with one transformer out-of-service for the 10% PoE demand forecast, and the hours per year that the 10% PoE demand is forecast is expected to exceed the (N-1) station rating. The graph also shows the value to customers of the expected unserved energy in each year, for the 10% PoE demand forecast. Review by: 12/2014 Page 76 of 309

78 Expected Energy at Risk above N-1 (kwh) and Hours at Risk above N-1 (hrs) Customer value of lost load ($) Strategy Figure 23 Annual energy, hours at risk and expected customer value of lost load at CFD Magnitude of load at risk above (N-1) and value of lost load at CFD 120 $8, $7,000 $6, $5, $4, $3,000 $2, $1, Year $0 Hours at risk above N-1 Expected energy above N-1 (kwhr) Customer value of lost load ($) 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 summer for about 6 hours. It is emphasised however that the probability of a major outage of one of the transformers occurring over the duration of high load is very low. When the energy at risk is weighted by this low probability, the expected energy at risk is estimated to be 43 kwh in summer If no action is taken, this figure is expected to rise to 110 kwh in summer , with a value to customers of around $6.9k. 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. Contingency plans to transfer load to adjacent zone substations. Plans to transfer load to adjacent zone substations at the distribution feeder level are established. These plans are reviewed annually prior to the summer season. Transfer capability away from CFD zone substation is assessed at over 9.1 MVA for summer Install a third 66/11kV transformer at a surrounding zone substation such as Elsternwick (EL), East Malvern (EM) or Gardiner (K). In the absence of any lower-cost options, installation of another transformer at EM is the most likely least cost technically feasible network option for addressing the limitations at CFD. The new transformer is likely beyond the next five years. Some load from CFD can be transferred away to EM once this augmentation has taken place. Review by: 12/2014 Page 77 of 309

79 3. Establish a new 66/11kV zone substation. There are no sites under consideration to be developed as a new zone substation to offload CFD. Preferred network option(s) for alleviation of limitations UE proposes to implement contingency plans to transfer load quickly to adjacent zone substations for an unplanned outage of a transformer at CFD zone substation under critical loading conditions until a long term solution is implemented. As a means of managing the risk at CFD and neighbouring Gardiner (K) zone substation, as well as catering for future developments within the Chadstone precinct, UE plans to install a third 66/11 kv transformer at EM, just beyond this planning period. Once commissioned, the distribution feeders shall be used to offload CFD zone substation onto EM zone substation. Therefore, no major demand related augmentation is planned at CFD zone substation over the next five years. Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. CFD zone substation Summer cyclic N Rating (MVA) 84.2 Summer cyclic N-1 Rating (MVA) 42.1 Embedded generation capacity (MW) 0.0 CFD zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 9.1 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 78 of 309

80 Load (MVA) Strategy 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. Being a designated Principal Activities Centre, the maximum demand around the Southland area is expected to continue to grow. Magnitude, probability and impact of loss of load CM is a summer-critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 24 Forecast maximum demand against station ratings for CM zone substation CM Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating The demand at CM zone substation is expected to remain within its (N-1) rating for the next five years. Therefore, no major demand related augmentation is planned at CM zone substation over the next five years. Review by: 12/2014 Page 79 of 309

81 Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. CM zone substation Summer cyclic N Rating (MVA) 61.8 Summer cyclic N-1 Rating (MVA) 30.9 Embedded generation capacity (MW) 0.0 CM zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 4.4 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 80 of 309

82 Load (MVA) Strategy 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 and Sandhurst. In December 2009, the station was augmented with a third 20/33 MVA 66/22 kv transformer together with three new distribution feeders. Demand growth at CRM is expected to continue with the ongoing development of new residential and industrial estates and committed load increases from a major customer in the Bangholme area. Magnitude, probability and impact of loss of load CRM is a summer-critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 25 Forecast maximum demand against station ratings for CRM zone substation CRM Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating During summer , the actual maximum demand at CRM exceeded its (N-1) rating. Given a steady demand growth over the next five years, a significant amount of energy would be at risk in the event of a forced transformer outage during maximum demand periods. Review by: 12/2014 Page 81 of 309

83 Expected Energy at Risk above N-1 (kwh) and Hours at Risk above N-1 (hrs) Customer value of lost load ($) Strategy The figure below depicts the expected energy at risk with one transformer out-of-service for the 10% PoE demand forecast, and the hours per year that the 10% PoE demand forecast is expected to exceed the (N-1) station rating. The graph also shows the value to customers of the expected unserved energy in each year, for the 10% PoE demand forecast. Figure 26 Annual energy, hours at risk and expected customer value of lost load at CRM Magnitude of load at risk above (N-1) and value of lost load at CRM 1400 $80, $70, $60,000 $50,000 $40,000 $30,000 $20,000 $10, Year $0 Hours at risk above N-1 Expected energy above N-1 (kwhr) Customer value of lost load ($) 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 summer for about 13 hours. It is emphasised however that the probability of a major outage of one of the transformers occurring over the duration of high load is very low. When the energy at risk is weighted by this low probability, the expected energy at risk is estimated to be 152 kwh in summer If no action is taken, this figure is expected to rise to 1,146 kwh in summer , with a value to customers of around $72.3k. 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. Contingency plans to transfer load to adjacent zone substations. Plans to transfer load to adjacent zone substations at the distribution feeder level are established. These plans are reviewed annually prior to the summer season. Transfer capability away from CRM zone substation is assessed at 17.3 MVA for summer Establish a new 66/22 kv zone substation. There are no vacant zone substation sites held by UE in the area. This option is regarded as a long-term solution to supply the growing Review by: 12/2014 Page 82 of 309

84 electricity demand in the area and would be economical in future, ideally situated in the Carrum Downs or Skye areas. 3. Install new transformation at an adjacent zone substation. A possible option is to install a third 66/22 kv transformer at Frankston (FTN) zone substation. Already the LWN second transformer is a committed project and is planned to be commissioned for summer to partly alleviate the constraints at CRM. Preferred network option(s) for alleviation of limitations 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 until a longer term solution is implemented. Distribution feeder transfers shall be used to transfer load to Langwarrin (LWN) once the committed second 66/22 kv transformer is commissioned by December (Refer to the Langwarrin zone substation risk assessment section). Therefore, no major demand related augmentation is planned at CRM zone substation over the next five years. Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. CRM zone substation Summer cyclic N Rating (MVA) Summer cyclic N-1 Rating (MVA) 73.9 Embedded generation capacity (MW) 0.0 CRM zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 17.3 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) ,146 Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 83 of 309

85 Load (MVA) Strategy Doncaster zone substation Doncaster (DC) zone substation is fully developed with three 20/27 MVA 66/22 kv transformers and supplies the areas of Box Hill Central, Box Hill North, Doncaster, Doncaster East, Doncaster Hill and The Pines precincts, and Templestowe. 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. Magnitude, probability and impact of loss of load DC is a summer-critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 27 Forecast maximum demand against station ratings for DC zone substation DC Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating During summer , the maximum demand at DC exceeded its (N-1) rating. Given a steady demand growth over the next five years, a significant amount of energy would be at risk in the event of a forced transformer outage during maximum demand periods. The chart below depicts the expected energy at risk with one transformer out-of-service for the 10% PoE demand forecast, and the hours per year that the 10% PoE demand forecast is expected to exceed the (N-1) station rating. The graph also shows the value to customers of the expected unserved energy in each year, for the 10% PoE demand forecast. Review by: 12/2014 Page 84 of 309

86 Expected Energy at Risk above N-1 (kwh) and Hours at Risk above N-1 (hrs) Customer value of lost load ($) Strategy Figure 28 Annual energy, hours at risk and expected customer value of lost load at DC Magnitude of load at risk above (N-1) and value of lost load at DC 600 $35, $30, $25,000 $20,000 $15,000 $10, $5, Year $0 Hours at risk above N-1 Expected energy above N-1 (kwhr) Customer value of lost load ($) 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 summer for about 8 hours. It is emphasised however that the probability of a major outage of one of the transformers occurring over the duration of high load is very low. When the energy at risk is weighted by this low probability, the expected energy at risk is estimated to be 117 kwh in summer If no action is taken, this figure is expected to rise to 507 kwh in summer , with a value to customers of around $32k. 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. Contingency plans to transfer load to adjacent zone substations. Plans to transfer load to adjacent zone substations at the distribution feeder level are established. These plans are reviewed annually prior to the summer season. Transfer capability away from DC zone substation is assessed at 20.8 MVA for summer Establish a new 66/22kV zone substation. Since DC is a fully developed zone substation, establishing a new zone substation is possibly the least cost technically feasible network option for the long term. Templestowe was identified as a suitable locality for a new zone substation to offload DC because it allows the distribution feeder lengths to be cut in half, effectively doubling the supply reliability for the area. This area currently contains some of UE s worst performing feeders with levels of reliability below the UE average. Accordingly, in 2012, UE purchased a site in Templestowe for this proposed new zone substation. The cost of this augmentation is estimated to be $18 million (excludes the cost of land acquired Review by: 12/2014 Page 85 of 309

87 in 2012). The new zone substation would be incorporated into the existing TSTS-WD-BU- TSTS sub-transmission system. 3. Install a fourth 66/22 kv transformer at DC. This option will alleviate the capacity limitation at DC but the resulting high 22 kv fault levels will need to be managed by a 22 kv bus split system with a suitable auto-close control scheme. This is able to be achieved by adopting a similar arrangement to that used at SV/SVW. Preferred network option(s) for alleviation of limitations UE proposes to implement contingency plans to transfer load quickly to adjacent zone substations for an unplanned outage of a transformer at DC under critical loading conditions. Whilst no decision has yet been made on a preferred network augmentation, the establishment of a new zone substation at Templestowe (TSE) or, augmentation of DC with a fourth transformer (with some sub-transmission reinforcements) are being considered as being the most likely network options. The timing of this augmentation is expected to be no earlier than December These plans will be undertaken in the absence of any commitment by interested parties to offer network support services by installing local generation or through demand side management initiatives that would reduce demand at DC. In 2012, UE signed a Memorandum of Understanding (MoU) with Manningham City Council to work cooperatively on common planning issues, particularly those involving the Doncaster Hill Smart Energy Zone precinct. The MoU allows UE to provide its expertise in electricity distribution to assist Council to explore and facilitate projects which promote sustainable energy development within the precinct. UE is supportive of and has been actively engaged with Council in its District Energy Services Scheme project and is keen to see the project develop into fruition. UE and Manningham City Council are eager to attract non-network solutions to this precinct (or the surrounding Bulleen (BU), Nunawading (NW) and West Doncaster (WD) supply areas) and welcome any proposals which could potentially defer augmentation in this area under a network support agreement with UE. Therefore, no major demand related augmentation is planned at DC zone substation over the next five years. Review by: 12/2014 Page 86 of 309

88 Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. DC zone substation Summer cyclic N Rating (MVA) Summer cyclic N-1 Rating (MVA) 73.6 Embedded generation capacity (MW) 0.0 DC zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 20.8 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 87 of 309

89 Load (MVA) Strategy Dromana zone substation Dromana (DMA) zone substation consists of one 20/33 MVA 66/22 kv transformer and supplies the areas of Dromana, Mount Martha, Red Hill and Shoreham. DMA was commissioned in March 2006 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. Magnitude, probability and impact of loss of load DMA is a summer-critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the nameplate rating. Figure 29 Forecast maximum demand against station ratings for DMA zone substation DMA Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating Nameplate Rating The (N-1) rating at DMA zone substation is zero because it is a single transformer zone substation. DMA is reliant on distribution feeder transfer capability from adjacent zone substations and deployment of the CDA relocatable transformer to cater for an outage of the main transformer. This transfer capacity is now depleting because of the demand growth. During the last two summers, the actual maximum demand at DMA zone substation exceeded the transformer name plate rating. Based on the present forecast, the maximum demand at DMA is expected to reach the N cyclic rating in summer Sub-transmission line circuit breakers are installed at DMA to prevent a single sub-transmission line fault tripping the zone substation transformer. Whilst the probability of a transformer failure is Review by: 12/2014 Page 88 of 309

90 Expected Energy at Risk above N-1 (kwh) and Hours at Risk above N-1 (hrs) Customer value of lost load ($) Strategy very low, the energy at 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 below depicts the expected energy at risk with one transformer out-of-service for the 10% PoE demand forecast, and the hours per year that the 10% PoE demand forecast is expected to exceed the (N-1) station rating. The graph also shows the value to customers of the expected unserved energy in each year, for the 10% PoE demand forecast. Figure 30 Annual energy, hours at risk and expected customer value of lost load at DMA Magnitude of load at risk above (N-1) and value of lost load at DMA $17,000, $16,500, $16,000,000 $15,500,000 $15,000,000 $14,500, $14,000, Year $13,500,000 Hours at risk above N-1 Expected energy above N-1 (kwhr) Customer value of lost load ($) The customers supplied from DMA zone substations are exposed to extended outage, in the event of a transformer failure, all year round. As a result, the expected energy at risk is very high. In summer , the expected energy at risk is estimated to be 233 MWh. If no action is taken, this figure is expected to rise to 262 MWh in summer , with a value to customers of around $16.6 million. To reduce this risk, UE has installed remote controlled switches on every feeder to enable the load supplied by DMA to be transferred quickly and easily to adjacent zone substations in the event of a fault. DMA has also been designed to accept the 20 MVA relocatable transformer currently stationed at CDA. Therefore the actual expected energy at risk is considerably lower than that indicated above. 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. Review by: 12/2014 Page 89 of 309

91 1. Contingency plans to transfer load to adjacent zone substations. Plans to transfer load to adjacent zone substations at the distribution feeder level are established. These plans are reviewed annually prior to the summer season. Transfer capability away from DMA zone substation is assessed at 25 MVA for summer , which is much less than that required to fully recover all DMA load for a failure of the DMA transformer at maximum demand. Works have been completed at DMA to allow the relocatable transformer to be connected should a major transformer fault occur. 2. Establish a new 66/22 kv zone substation. There are no vacant zone substation sites in the area, and the cost of acquiring a new site together with the construction of new subtransmission lines would very likely make such an option uneconomic. 3. Install a second 66/22 kv transformer at DMA. This is most likely the least cost technically feasible network option. 4. Demand reduction, up to 17 MW in the first year, then in the order of 2 MW thereafter, connected within the DMA supply areas by December 2015, can defer the need for augmentation at DMA zone substation. UE has developed a number of innovative network tariffs that encourage voluntary demand reduction during times of network limitation. The amount of demand reduction depends on the tariff uptake and will be taken into consideration when determining the optimum timing for the capacity augmentation. 5. Embedded generation at DMA zone substation up to 17 MW in the first year, then in the order of 2 MW thereafter, connected within the DMA supply areas by December 2015, can defer the need for augmentation at DMA zone substation. Preferred network option(s) for alleviation of limitations The expected energy at risk is sufficient to economically justify the installation of the second transformer at DMA. As a result, UE plans to install a second transformer at DMA by December 2015 at an estimated cost of $8.3 million. This plan will be undertaken in the absence of any commitment by interested parties to offer network support services through demand side management initiatives that would reduce load at DMA. The estimated total annual cost of the preferred network option is $830,000. This cost provides a broad upper bound indication of the maximum contribution from UE which may be available to non-network service providers to reduce forecast demand and defer or avoid this augmentation. Until the installation of the second transformer at DMA, UE proposes to maintain contingency plans to transfer load quickly to adjacent zone substations for an unplanned outage of the DMA transformer and deploy the relocatable transformer in the event of a major outage. UE intends to undertake a detailed assessment of this limitation in a Regulatory Investment Test for Distribution (RIT-D) in the first half of 2014, to identify the preferred solution to alleviate the limitations at DMA zone substation. UE invites non-network service providers to submit their proposals to alleviate limitations at Dromana (DMA) zone substation. Review by: 12/2014 Page 90 of 309

92 Station summary The table below provides more detailed data on the station rating, demand forecasts, energy at risk and expected unserved energy. DMA zone substation Summer cyclic N Rating (MVA) 44.8 Summer cyclic N-1 Rating (MVA) 0.0 Embedded generation capacity (MW) 0.0 DMA zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 25.0 N-1 energy at risk at 10% PoE demand (MWh) 187, , , , ,746 N-1 expected hours at risk at 10% PoE demand (hours) 8,760 8,760 8,760 8,760 8,760 N-1 expected energy at risk at 10% PoE demand (kwh) 233, , , , ,384 Expected unserved energy at 10% PoE demand ($k) 14,719 15,252 15,717 16,159 16,554 Review by: 12/2014 Page 91 of 309

93 Load (MVA) Strategy 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, and supplies the areas of Dandenong, Doveton, Endeavour Hills and Hallam. Two embedded generation schemes over 1 MW in the area helps to reduce demand at DN by approximately 5 MW on weekdays between 7:00am and 11:00pm. 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. Magnitude, probability and impact of loss of load DN is a summer-critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 31 Forecast maximum demand against station ratings for DN zone substation DN Summer Maximum Demand Year Actual Load with Generation Summer (N) Rating Actual Load without Generation Forecast Load with Generation Summer (N-1) Rating Forecast Load without Generation With the embedded generation, the demand at DN zone substation is expected to exceed its (N-1) rating from summer The figure below depicts the expected energy at risk with one transformer out-of-service for the 10% PoE demand forecast, and the hours per year that the 10% PoE demand is forecast is expected to exceed the (N-1) station rating. The graph also shows the value to customers of the expected unserved energy in each year, for the 10% PoE demand forecast. Review by: 12/2014 Page 92 of 309

94 Expected Energy at Risk above N-1 (kwh) and Hours at Risk above N-1 (hrs) Customer value of lost load ($) Strategy Figure 32 Annual energy, hours at risk and expected customer value of lost load at DN Magnitude of load at risk above (N-1) and value of lost load at DN Including Generation 80 $5, $4,500 $4,000 $3,500 $3, Year $2,500 $2,000 $1,500 $1,000 $500 $0 Hours at risk above N-1 Expected energy above N-1 (kwhr) Customer value of lost load ($) As shown above, if there is a forced transformer outage during summer maximum demand periods, there will be insufficient capacity at DN zone substation to supply all demand in summer for about 2 hours. It is emphasised however that the probability of a major outage of one of the transformers occurring over the duration of high load is very low. When the energy at risk is weighted by this low probability, the expected energy at risk is estimated to be 17 kwh in summer If no action is taken, this figure is expected to rise to 74 kwh in summer , with a value to customers of around $4.7k. In the absence of the embedded generation, the expected energy at risk is estimated to be to be 6 kwh in summer If no action is taken, this figure is expected to rise to 151 kwh in summer , with a value to customers of around $9.5k. To limit this risk, load can be transferred from DN to Lyndale (LD) zone substation, where a third transformer was installed in December 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 limitations. 1. Contingency plans to transfer load to adjacent zone substations. Plans to transfer load to adjacent zone substations at the distribution feeder level are established. These plans are reviewed annually prior to the summer season. Transfer capability away from DN zone substation is assessed at 19.2 MVA for summer Review by: 12/2014 Page 93 of 309

95 2. Establish a new 66/22 kv zone substation. UE owns land for a future Dandenong City (DNC) zone substation, west of DN, however there is currently no need to develop this site given the committed Keysborough zone substation project. To supply the growing electricity demand in the area around DN it is likely that a new site further north of DN will need to be acquired to accommodate growth north of the zone substation. 3. Enter into a network support agreement with the embedded generators connected to DN zone substation to reduce the energy at risk once it becomes more significant. Preferred network option(s) for alleviation of limitations Given the energy at risk is insufficient to justify augmentation, UE proposes to implement contingency plans to transfer load quickly to adjacent zone substations for an unplanned outage of a transformer at DN under critical loading conditions. As a result, no major demand related augmentation is planned at DN zone substation over the next five years. Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. DN zone substation Summer cyclic N Rating (MVA) Summer cyclic N-1 Rating (MVA) 84.2 Embedded generation capacity (MW) 5.0 DN zone substation (With generation) % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 19.2 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 94 of 309

96 Load (MVA) Strategy 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. Magnitude, probability and impact of loss of load DSH is a summer-critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 33 Forecast maximum demand against station ratings for DSH zone substation DSH Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating The demand at DSH zone substation is expected to exceed its (N-1) rating from summer UE plans to commission the new Keysborough (KBH) zone substation in December Once commissioned, load will be transferred away from DSH to KBH as shown in the figure above. The figure below depicts the expected energy at risk with one transformer out-of-service for the 10% PoE demand forecast, and the hours per year that the 10% PoE demand forecast is expected to exceed the (N-1) station rating. The graph also shows the value to customers of the expected unserved energy in each year, for the 10% PoE demand forecast. Review by: 12/2014 Page 95 of 309

97 Expected Energy at Risk above N-1 (kwh) and Hours at Risk above N-1 (hrs) Customer value of lost load ($) Strategy Figure 34 Annual energy, hours at risk and expected customer value of lost load at DSH Magnitude of load at risk above (N-1) and value of lost load at DSH 450 $30, $25, $20, $15,000 $10, Year $5,000 $0 Hours at risk above N-1 Expected energy above N-1 (kwhr) Customer value of lost load ($) As shown above, if there is a forced transformer outage during summer maximum demand periods, there will be insufficient capacity at DSH zone substation to supply all demand in summer for about 72 hours. It is emphasised however that the probability of a major outage of one of the transformers occurring over the duration of high load is very low. When the energy at risk is weighted by this low probability, the expected energy at risk is estimated to be 403 kwh in summer With the load transfer from DSH to KBH, this figure is expected to fall to 44 kwh in summer , with a value to customer of around $2.8k. 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. Contingency plans to transfer load to adjacent zone substations. Plans to transfer load to adjacent zone substations at the distribution feeder level are established. These plans are reviewed annually prior to the summer season. Transfer capability away from DSH zone substation is assessed at 28.8 MVA for summer Install a fourth transformer at DSH zone substation. There is sufficient space available at the existing DSH switchyard to accommodate a fourth transformer. With the installation of a fourth transformer at DSH, it would be proposed to split the existing 22 kv outdoor bus into two sections to manage the fault levels on the 22 kv buses. The fourth transformer will be paralleled with the existing Transformer No.1 to form a separate 22 kv indoor bus while the connections to Transformer No.2 and No.3 remain unaltered. A dedicated 22 kv bus tie cable would be installed between the existing outdoor and new indoor buses. This bus tie would remain open during normal operation and two buses will operate independently of Review by: 12/2014 Page 96 of 309

98 each other. This arrangement is similar to the 22 kv connections between Springvale (SV) and Springvale West (SVW) zone substations. 3. Transfer additional load from DSH to the new KBH zone substation to be commissioned in December Preferred network option(s) for alleviation of limitations UE proposes to maintain contingency plans to transfer load quickly to adjacent zone substations for an unplanned outage of a transformer at DSH under critical loading conditions until a longer term solution is implemented. UE plans to commission the new Keysborough (KBH) zone substation in December Once commissioned, distribution feeder works shall be used to transfer load from DSH to KBH for the remainder of the planning period. As a result, no major demand related augmentation is planned at DSH zone substation over the next five years. Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. DSH zone substation Summer cyclic N Rating (MVA) 91.9 Summer cyclic N-1 Rating (MVA) 61.3 Embedded generation capacity (MW) 0.0 DSH zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 28.8 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 97 of 309

99 Load (MVA) Strategy 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. The third 20/33MVA transformer was installed in 2011 to replace the 12/20 MVA relocatable transformer, which was stationed at DVY. The relocatable transformer has been moved to CDA zone substation. Magnitude, probability and impact of loss of load DVY is a summer-critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 35 Forecast maximum demand against station ratings for DVY zone substation DVY Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating The demand at DVY zone substation is expected to exceed its (N-1) rating from summer The figure below depicts the expected energy at risk with one transformer out-of-service for the 10% PoE demand forecast, and the hours per year that the 10% PoE demand is forecast is expected to exceed the (N-1) station rating. The graph also shows the value to customers of the expected unserved energy in each year, for the 10% PoE demand forecast. Review by: 12/2014 Page 98 of 309

100 Expected Energy at Risk above N-1 (kwh) and Hours at Risk above N-1 (hrs) Customer value of lost load ($) Strategy Figure 36 Annual energy, hours at risk and expected customer value of lost load at DVY Magnitude of load at risk above (N-1) and value of lost load at DVY 120 $7, $6, $5,000 $4,000 $3,000 $2, $1, Year $0 Hours at risk above N-1 Expected energy above N-1 (kwhr) Customer value of lost load ($) As shown above, if there is a forced transformer outage during summer maximum demand periods, there will be insufficient capacity at DVY zone substation to supply all demand in summer for about 1 hour. It is emphasised however that the probability of a major outage of one of the transformers occurring over the duration of high load is very low. When the energy at risk is weighted by this low probability, the expected energy at risk is estimated to be 1 kwh in summer This figure is expected to rise to 103 kwh in summer , with a value to customers of around $6.5k. 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. Contingency plans to transfer load to adjacent zone substations. Plans to transfer load to adjacent zone substations at the distribution feeder level are established. These plans are reviewed annually prior to the summer season. Transfer capability away from DVY zone substation is approximately 20.9 MVA for summer Installing line capacitors at DVY high voltage feeders to improve the power factor. Preferred network option(s) for alleviation of limitations Given the expected energy at risk is insufficient to justify augmentation, UE proposes to maintain contingency plans to transfer load quickly to adjacent zone substations for an unplanned outage of a transformer at DVY under critical loading conditions. Therefore, no major demand related augmentation is planned at DVY zone substation over the next five years Review by: 12/2014 Page 99 of 309

101 Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. DVY zone substation Summer cyclic N Rating (MVA) Summer cyclic N-1 Rating (MVA) 87.8 Embedded generation capacity (MW) 0.0 DVY zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 20.9 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 100 of 309

102 Load (MVA) Strategy East Burwood zone substation East Burwood (EB) zone substation is fully developed with three 20/30 MVA 66/22 kv transformers and supplies the suburbs of Burwood East and Forest Hill. Magnitude, probability and impact of loss of load EB is a summer-critical zone substation. The figure below depicts the 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant inservice) and the (N-1) rating. Figure 37 Forecast maximum demand against station ratings for EB zone substation EB Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating The forecast demand at EB zone substation is expected to marginally exceed its (N-1) rating from summer However, the expected energy at risk is insignificant over the planning period. Therefore, no major demand related augmentation is planned at EB zone substation over the next five years. Review by: 12/2014 Page 101 of 309

103 Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. EB zone substation Summer cyclic N Rating (MVA) Summer cyclic N-1 Rating (MVA) 67.8 Embedded generation capacity (MW) 0.0 EB zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 17.1 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 102 of 309

104 Load (MVA) Strategy Elsternwick zone substation Elsternwick (EL) zone substation consists of two 20/27 MVA 66/11 kv transformers and supplies the area of Elsternwick. In 2012, the 11 kv transformer cables were replaced to increase the station s (N) and (N-1) ratings by 9.8 MVA and 4.9 MVA respectively. Magnitude, probability and impact of loss of load EL is a summer-critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 38 Forecast maximum demand against station ratings for EL zone substation EL Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating The forecast demand at EL zone substation is expected to marginally exceed its (N-1) rating from summer However, the expected energy at risk is insignificant within the planning period. Therefore, no major demand related augmentation is planned at EL zone substation over the next five years. Review by: 12/2014 Page 103 of 309

105 Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. EL zone substation Summer cyclic N Rating (MVA) 66.9 Summer cyclic N-1 Rating (MVA) 33.4 Embedded generation capacity (MW) 0.0 EL zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 8.4 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 104 of 309

106 Load (MVA) Strategy 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. Magnitude, probability and impact of loss of load EM is a summer-critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 39 Forecast maximum demand against station ratings for EM zone substation EM Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating During summer , the maximum demand at EM exceeded its (N-1) rating. Given a steady demand growth over the next five years, a significant amount of energy would be at risk in the event of a forced transformer outage during maximum demand periods. The graph chart below depicts the expected energy at risk with one transformer out-of-service for the 10% PoE demand forecast, and the hours per year that the 10% PoE demand forecast is expected to exceed the (N-1) station rating. The graph also shows the value to customers of the expected unserved energy in each year, for the 10% PoE demand forecast. Review by: 12/2014 Page 105 of 309

107 Expected Energy at Risk above N-1 (kwh) and Hours at Risk above N-1 (hrs) Customer value of lost load ($) Strategy Figure 40 Annual energy, house at risk and expected customer value of lost load at EM Magnitude of load at risk above (N-1) and value of lost load at EM 90 $6, $5, $4, $3,000 $2, Year $1,000 $0 Hours at risk above N-1 Expected energy above N-1 (kwhr) Customer value of lost load ($) 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 summer for about 6 hours. It is emphasised however that the probability of a major outage of one of the transformers occurring over the duration of high load is very low. When the energy at risk is weighted by this low probability, the expected unserved energy is estimated to be 29 kwh in summer If no action is taken, this figure is expected to rise to 81 kwh in summer , with a value to customers of around $5.1k. 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. Contingency plans to transfer load to adjacent zone substations. Plans to transfer load to adjacent zone substations at the distribution feeder level are established. These plans are reviewed annually prior to the summer season. Transfer capability away from EM zone substation is assessed at 9.8 MVA for summer Establish a new 66/11 kv zone substation. There are no vacant zone substation sites in the area and 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. 3. Install a third 66/11 kv transformer at EM. Review by: 12/2014 Page 106 of 309

108 Preferred network option(s) for alleviation of limitations Given the expected energy at risk is insufficient to justify augmentation, UE proposes to implement contingency plans to transfer load quickly to adjacent zone substations for an unplanned outage of a transformer at EM under critical loading conditions. As a means of managing the risk at neighbouring Caulfield (CFD) and Gardiner (K) as well as catering for future developments around the Chadstone precinct, UE plans to install a third 66/11 kv transformer at EM, just beyond this planning period. Once commissioned, UE shall use the distribution feeders to offload CFD and K zone substations onto EM zone substation. Therefore, no major demand related augmentation is planned at EM zone substation over the next five years. Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. EM zone substation Summer cyclic N Rating (MVA) 63.9 Summer cyclic N-1 Rating (MVA) 31.9 Embedded generation capacity (MW) 0.0 EM zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 9.8 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 107 of 309

109 Load (MVA) Strategy Elwood zone substation Elwood (EW) zone substation consists of two 20/30MVA 66/11kV transformers and supplies the area of Elwood. Magnitude, probability and impact of loss of load EW is a summer-critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 41 Forecast maximum demand against station ratings at EW zone substation EW Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating The demand at EW zone substation is expected to remain within its (N-1) rating for the next five years. Therefore, no major demand related augmentation is planned at EW zone substation over the next five years. Review by: 12/2014 Page 108 of 309

110 Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. EW zone substation Summer cyclic N Rating (MVA) 58.8 Summer cyclic N-1 Rating (MVA) 29.4 Embedded generation capacity (MW) 0.0 EW zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 5.4 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 109 of 309

111 Load (MVA) Strategy 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. Being a designated Central Activities District, the maximum demand in the Frankston area is expected to continue to grow steadily over coming years. During the January 2009 heatwave event, transformers No.1 and the old 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 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 was anticipated to have around 6 to 7 years of life remaining. UE replaced the transformer No.3 in 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. Magnitude, probability and impact of loss of load FSH is a summer-critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 42 Forecast maximum demand against station ratings for FSH zone substation FSH Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating Review by: 12/2014 Page 110 of 309

112 Expected Energy at Risk above N-1 (kwh) and Hours at Risk above N-1 (hrs) Customer value of lost load ($) Strategy In November 2009, a new zone substation was established in Langwarrin (LWN). This enabled load to be transferred from FSH and Frankston (FTN) zone substations to LWN as shown in the graph above. During summer , the maximum demand at FSH marginally exceeded the station s (N-1) rating. Given a steady demand growth over the next five years, a significant amount of energy would be at risk in the event of a forced transformer outage during maximum demand periods. The figure below depicts the expected energy at risk with one transformer out-of-service for the 10% PoE demand forecast, and the hours per year that the 10% PoE demand forecast is expected to exceed the (N-1) station rating. The graph also shows the value to customers of the expected unserved energy in each year, for the 10% PoE demand forecast. Figure 43 Annual energy, hours at risk and expected customer value of lost load at FSH Magnitude of load at risk above (N-1) and value of lost load at FSH 400 $25, $20, $15, $10, $5, Year $0 Hours at risk above N-1 Expected energy above N-1 (kwhr) Customer value of lost load ($) 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 summer for about 11 hours. It is emphasised however that the probability of a major outage of one of the transformers occurring over the duration of high load is very low. When the energy at risk is weighted by this low probability, the expected unserved energy is estimated to be 187 kwh in summer If no action is taken, this figure is expected to rise to 368 kwh in summer , with a value to customers of around $23.2k. 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. Review by: 12/2014 Page 111 of 309

113 1. Contingency plans to transfer load to adjacent zone substations. Plans to transfer load to adjacent zone substations at the distribution feeder level are established. These plans are reviewed annually prior to the summer season. Transfer capability away from FSH zone substation is assessed at 18.4 MVA for summer Works have been completed to allow the relocatable transformer to be connected at FSH should a major transformer fault occur. 2. Install new transformer at an adjacent zone substation. A third 66/22 kv transformer at Frankston (FTN) zone substation would help FSH however long expensive distribution feeders would be required to reduce load at FSH substantially. Likewise additional capacity at Mornington (MTN) zone substation would also require long expensive distribution feeders to transfer substantial load from FSH. A second 66/22 kv transformer at LWN offers 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. Installation of a second 66/22 kv transformer at LWN is now a committed project and is expected to be commissioned in December Establish a new 66/22 kv zone substation. UE owns land in the Somerville area for a future 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. 4. Feeder load transfers. FTN and MTN zone substations operate above their (N-1) ratings and do not have sufficient spare capacity to absorb demand from FSH on a permanent basis. Some load can be transferred from FSH to LWN once the second LWN transformer is commissioned in December Replace the FSH transformer No.1 by December 2020 (as an asset replacement project). Preferred network option(s) for alleviation of limitations 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 until a longer term solution is implemented. Distribution feeder works shall be used to transfer load from FSH to LWN once the second 66/22 kv transformer is commissioned in December In addition, UE plans to replace the FSH transformer No.1 by December Once commissioned, the station s rating would be adequate to meet the demand at FSH beyond this planning period. As a result, no major demand related augmentation is planned at FSH zone substation over the next five years. Review by: 12/2014 Page 112 of 309

114 Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. FSH zone substation Summer cyclic N Rating (MVA) 93.0 Summer cyclic N-1 Rating (MVA) 62.0 Embedded generation capacity (MW) 0.0 FSH zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 18.4 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 113 of 309

115 Load (MVA) Strategy 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. Being a designated Central Activities District, the maximum demand in the Frankston area is expected to continue to grow steadily over coming years. In November 2009, a new zone substation was established in Langwarrin (LWN). This enabled load to be transferred from FTN to LWN. Magnitude, probability and impact of loss of load FTN is a summer-critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 44 Forecast maximum demand against station ratings for FTN zone substation FTN Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating During summer , the maximum demand at FTN zone substation exceeded its (N-1) rating. Given a steady demand growth over the next five years, a significant amount of energy would be at risk in the event of a forced transformer outage during maximum demand periods. The figure below depicts the expected energy at risk with one transformer out-of-service for the 10% PoE demand forecast, and the hours per year that the 10% PoE demand forecast is expected to exceed the (N-1) station rating. The graph also shows the value to customers of the expected unserved energy in each year, for the 10% PoE demand forecast. Review by: 12/2014 Page 114 of 309

116 Expected Energy at Risk above N-1 (kwh) and Hours at Risk above N-1 (hrs) Customer value of lost load ($) Strategy Figure 45 Annual energy, hours at risk and expected customer value of lost load at FTN Magnitude of load at risk above (N-1) and value of lost load at FTN 350 $25, $20, $15, $10, $5, Year $0 Hours at risk above N-1 Expected energy above N-1 (kwhr) Customer value of lost load ($) 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 summer for about 9 hours. It is emphasised however that the probability of a major outage of one of the transformers occurring over the duration of high load is very low. When the energy at risk is weighted by this low probability, the expected unserved energy is estimated to be 104 kwh in summer If no action is taken, this figure is expected to rise to 307 kwh in summer , with a value to customers of around $19.4k. To limit this risk, load can be transferred from FTN to Langwarrin (LWN) zone substation following the installation of the second 66/22 kv transformer at LWN in December Therefore, the actual expected energy at risk is likely to be lower from summer than indicated above. 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. Contingency plans to transfer load to adjacent zone substations. Plans to transfer load to adjacent zone substations at the distribution feeder level are established. These plans are reviewed annually prior to the summer season. Transfer capability away from FTN zone substation is assessed at 16.4 MVA for summer Install a third 66/22kV transformer at FTN. 3. Install new transformer at an adjacent zone substation. Carrum (CRM) zone substation is already fully developed with three transformers thus a second 66/22kV transformer at Review by: 12/2014 Page 115 of 309

117 Langwarrin (LWN) to the south offers the best solution by providing limited load relief for FTN while also providing LWN with an (N-1) rating reducing energy at risk all year round. Installation of a second 66/22kV transformer at LWN is now a committed project and is expected to be commissioned in December Feeder load transfers. FSH and CRM zone substations operate above their (N-1) ratings and do not have sufficient spare capacity to absorb demand from FTN on a permanent basis. Some load can be transferred from FTN to LWN once the second LWN transformer is commissioned in December Establish a new 66/22kV zone substation. There are no vacant zone substation sites in the area and the cost of acquiring a new site together with the construction of new subtransmission lines 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 Carrum Downs or Skye area. Preferred network option(s) for alleviation of limitations 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. Distribution feeder works shall be used to transfer load from FTN to LWN once the second 66/22 kv transformer is commissioned in December (Refer to the Langwarrin zone substation risk assessment section). As a result, no major demand related augmentation is planned at FTN zone substation over the next five years. Review by: 12/2014 Page 116 of 309

118 Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. FTN zone substation Summer cyclic N Rating (MVA) 91.2 Summer cyclic N-1 Rating (MVA) 45.6 Embedded generation capacity (MW) 0.0 FTN zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 16.4 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 117 of 309

119 Load (MVA) Strategy Glen Waverley zone substation Glen Waverley (GW) zone substation is developed with three 20/27 MVA 66/22 kv transformers and supplies the areas of Glen Waverley, Mount Waverley and Wantirna South. Being a designated Principal Activities Centre, the demand in the Glen Waverley area is expected to continue to grow over coming years. Magnitude, probability and impact of loss of load GW is a summer-critical zone substation. The figure below depicts the 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant inservice) and the (N-1) rating. Figure 46 Forecast maximum demand against station ratings for GW zone substation GW Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating The demand at GW zone substation is expected to exceed its (N-1) rating from summer The figure below depicts the expected energy at risk with one transformer out-of-service for the 10% PoE demand forecast, and the hours per year that the 10% PoE demand forecast is expected to exceed the (N-1) station rating. The graph also shows the value to customers of the expected unserved energy in each year, for the 10% PoE demand forecast. Review by: 12/2014 Page 118 of 309

120 Expected Energy at Risk above N-1 (kwh) and Hours at Risk above N-1 (hrs) Customer value of lost load ($) Strategy Figure 47 Annual energy, hours at risk and expected customer value of lost load at GW Magnitude of load at risk above (N-1) and value of lost load at GW 35 $2, $2, $1, $1, $ Year $0 Hours at risk above N-1 Expected energy above N-1 (kwhr) Customer value of lost load ($) 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 summer for about 2 hours. It is emphasised however that the probability of a major outage of one of the transformers occurring over the duration of high load is very low. When the energy at risk is weighted by this low probability, the expected energy at risk is estimated to be 7 kwh in summer If no action is taken, this figure is expected to rise to 31 kwh in summer , with a value to customers of around $1.9k. 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. Contingency plans to transfer load to adjacent zone substations. Plans to transfer load to adjacent zone substations at the distribution feeder level are established. These plans are reviewed annually prior to the summer season. Transfer capability away from GW zone substation is assessed at 21.5 MVA for summer Establish a new 66/22 kv zone substation. There are no vacant zone substation sites in the area and 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. 3. Install new transformation at an adjacent zone substation. In the absence of any lowercost options, installation of a third 66/22 kv transformer at Notting Hill (NO) zone substation Review by: 12/2014 Page 119 of 309

121 is the most likely least cost, technically feasible network option for addressing limitations at GW. Some load from GW can be transferred away to NO once this augmentation is taken place. Preferred network option(s) for alleviation of limitations Given the expected energy at risk is insufficient to justify augmentation, UE proposes to implement contingency plans to transfer load quickly to adjacent zone substations for an unplanned outage of a transformer at GW under critical loading conditions. As a means of managing the risk at NO zone substation, UE plans to install a third 66/22 kv transformer at NO by December Once commissioned, the distribution feeders shall be used to offload GW zone substation onto NO zone substation. Therefore, no major demand related augmentation is planned at GW zone substation over the next five years. Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. GW zone substation Summer cyclic N Rating (MVA) Summer cyclic N-1 Rating (MVA) 68.9 Embedded generation capacity (MW) 0.0 GW zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 21.5 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 120 of 309

122 Load (MVA) Strategy 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. The demand in the Hastings area is expected to continue to grow over coming years with the possible expansion of the port. Magnitude, probability and impact of loss of load HGS is a summer-critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 48 Forecast maximum demand against station ratings for HGS zone substation HGS Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating The figure above shows that the demand at HGS zone substation has been above its (N-1) rating since summer Given a steady demand growth over the next five years, a significant amount of energy would be at risk in the event of a forced transformer outage during maximum demand periods. The figure below depicts the expected energy at risk with one transformer out-of-service for the 10% PoE demand forecast, and the hours per year that the 10% PoE demand forecast is expected to exceed the (N-1) station rating. The graph also shows the value to customers of the expected unserved energy in each year, for the 10% PoE demand forecast. Review by: 12/2014 Page 121 of 309

123 Expected Energy at Risk above N-1 (kwh) and Hours at Risk above N-1 (hrs) Customer value of lost load ($) Strategy Figure 49 Annual energy, hours at risk and expected customer value of lost load at HGS Magnitude of load at risk above (N-1) and value of lost load at HGS 2000 $120, $100, Year $80,000 $60,000 $40,000 $20,000 $0 Hours at risk above N-1 Expected energy above N-1 (kwhr) Customer value of lost load ($) 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 summer for about 129 hours. It is emphasised however that the probability of a major outage of one of the transformers occurring over the duration of high load is very low. When the energy at risk is weighted by this low probability, the expected unserved energy is estimated to be 656 kwh in summer If no action is taken, this figure is expected to rise to 1793 kwh in summer , with a value to customers of around $113.1k. 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. Contingency plans to transfer load to adjacent zone substations. Plans to transfer load to adjacent zone substations at the distribution feeder level are established. These plans are reviewed annually prior to the summer season. Transfer capability away from HGS zone substation is assessed at 20 MVA for summer Feeder load transfers. With the rebuild of Mornington (MTN) zone substation in 2012, limited load transfers from HGS to MTN may be possible. 3. Install new transformer at an adjacent zone substation. A possible option is to install a second 66/22kV transformer at Dromana (DMA) zone substation. 4. Add a third 66/22kV transformer at HGS zone substation. Review by: 12/2014 Page 122 of 309

124 5. Establish a new 66/22kV zone substation. UE currently owns a site in the Somerville area north of Hastings for a future 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. Preferred network option(s) for alleviation of limitations 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. UE will monitor the demand in the area over the next couple of years and the proposed port development before committing to any augmentation plans at HGS. A second transformer at Dromana (DMA) zone substation is likely by December New distribution feeders would be constructed with the second transformer and they could potentially be used to offload HGS in the event the growth remains. This is likely to defer the need to install a third transformer at HGS beyond the next five years. As a result, no major demand related augmentation is planned at HGS zone substation over the next five years. Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. HGS zone substation Summer cyclic N Rating (MVA) 79.8 Summer cyclic N-1 Rating (MVA) 39.9 Embedded generation capacity (MW) 0.0 HGS zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 20.0 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) 656 1,038 1,297 1,557 1,793 Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 123 of 309

125 Load (MVA) Strategy Heatherton zone substation Heatherton (HT) zone substation is developed with three 20/27 MVA 66/22 kv transformers and supplies the area of Heatherton. Magnitude, probability and impact of loss of load HT is a summer-critical zone substation. The figure below depicts the 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant inservice) and the (N-1) rating. Figure 50 Forecast maximum demand against station ratings for HT zone substation HT Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating The forecast demand at HT zone substation is expected to marginally exceed its (N-1) rating from summer However, the expected energy at risk is insignificant within the planning period. Therefore, no major demand related augmentation is planned at HT zone substation over the next five years. Review by: 12/2014 Page 124 of 309

126 Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. HT zone substation Summer cyclic N Rating (MVA) 92.8 Summer cyclic N-1 Rating (MVA) 61.9 Embedded generation capacity (MW) 0.0 HT zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 6.4 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 125 of 309

127 Load (MVA) Strategy 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. In 2012, the 11 kv transformer cables on transformer No.3 were replaced to increase the station s (N) and (N-1) by 9.6 MVA and 4.8 MVA respectively. Magnitude, probability and impact of loss of load K is a summer-critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 51 Forecast maximum demand against station ratings for K zone substation K Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating The figure above shows that the demand at K zone substation has been above its (N-1) rating since summer Given a steady demand growth over the next five years, a significant amount of energy would be at risk in the event of a forced transformer outage during maximum demand periods. The figure below depicts the expected energy at risk with one transformer out-of-service for the 10% PoE demand forecast, and the hours per year that the 10% PoE demand forecast is expected to exceed the (N-1) station rating. The graph also shows the value to customers of the expected unserved energy in each year, for the 10% PoE demand forecast. Review by: 12/2014 Page 126 of 309

128 Expected Energy at Risk above N-1 (kwh) and Hours at Risk above N-1 (hrs) Customer value of lost load ($) Strategy Figure 52 Annual energy, hours at risk and expected customer value of lost load at K Magnitude of load at risk above (N-1) and value of lost load at K 80 $5, $4,500 $4,000 $3,500 $3, Year $2,500 $2,000 $1,500 $1,000 $500 $0 Hours at risk above N-1 Expected energy above N-1 (kwhr) Customer value of lost load ($) 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 summer for about 5 hours. It is emphasised however that the probability of a major outage of one of the transformers occurring over the duration of high load is very low. When the energy at risk is weighted by this low probability, the expected unserved energy is estimated to be 45 kwh in summer If no action is taken, this figure is expected to rise to 69 kwh in summer , with a value to customers of around $4.4k. 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. Contingency plans to transfer load to adjacent zone substations. Plans to transfer load to adjacent zone substations at the distribution feeder level are established. These plans are reviewed annually prior to the summer season. Transfer capability away from K zone substation is assessed at 6.8 MVA for summer Establish a new 66/11 kv zone substation. There are no sites under consideration to be developed as a new zone substation to offload K. 3. Install a third 66/11 kv transformer at K. 4. Install a third 66/11kV transformer at a surrounding zone substation such as Elsternwick (EL) or East Malvern (EM). In the absence of any lower-cost options, installation of another transformer at EM is the most likely least cost technically feasible network option for Review by: 12/2014 Page 127 of 309

129 addressing the limitations at K. The new transformer is likely beyond the next five years. Some load from K can be transferred away to EM once this augmentation is taken place. Preferred network option(s) for alleviation of limitations Given the expected energy at risk is insufficient to justify augmentation, UE proposes to implement contingency plans to transfer load quickly to adjacent zone substations for an unplanned outage of a transformer at K under critical loading conditions. As a means of managing the risk at K and neighbouring Caulfield (CFD) zone substation, as well as catering for future developments around the Chadstone precinct, UE plans to install a third 66/11 kv transformer at EM, just beyond this planning period. Once commissioned, the distribution feeders shall be used to offload K zone substation onto EM zone substation. Therefore, no major demand related augmentation is planned at K zone substation over the next five years. Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. K zone substation Summer cyclic N Rating (MVA) 73.5 Summer cyclic N-1 Rating (MVA) 36.8 Embedded generation capacity (MW) 0.0 K zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 6.8 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 128 of 309

130 Load (MVA) Strategy Keysborough zone substation Keysborough (KBH) zone substation will consist of one 20/33 MVA 66/22 kv transformer and supply the areas of Dandenong, Keysborough and Noble Park. KBH is expected to be commissioned by December 2014 to provide load relief for Dandenong South (DSH), Mordialloc (MC) and Noble Park (NP) zone substations, as well as improving distribution feeder capacity and supply reliability in the area. Magnitude, probability and impact of loss of load KBH will be a summer-critical zone substation. The figure below depicts the 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant inservice) and the nameplate rating. Figure 53 Forecast maximum demand against station ratings for KBH zone substation KBH Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Nameplate Rating The (N-1) rating at KBH zone substation is zero because it will be a single transformer zone substation. KBH will be reliant on distribution feeder transfer capability from adjacent zone substations and deployment of the relocatable transformer to cater for an outage of the main transformer. The figure below depicts the expected energy at risk with one transformer out-of-service for the 10% PoE demand forecast, and the hours per year that the 10% PoE demand forecast is expected to exceed the (N-1) station rating. The graph also shows the value to customers of the expected unserved energy in each year, for the 10% PoE demand forecast. Review by: 12/2014 Page 129 of 309

131 Expected Energy at Risk above N-1 (kwh) and Hours at Risk above N-1 (hrs) Customer value of lost load ($) Strategy Figure 54 Annual energy, hours at risk and expected customer value of lost load at KBH Magnitude of load at risk above (N-1) and value of lost load at KBH $10,000, $9,000,000 $8,000,000 $7,000,000 $6,000, Year $5,000,000 $4,000,000 $3,000,000 $2,000,000 $1,000,000 $0 Hours at risk above N-1 Expected energy above N-1 (kwhr) Customer value of lost load ($) As shown above, if there is a forced transformer outage during summer maximum demand period, the customers supplied from KBH zone substation are exposed to such an event all year round. As a result, the expected energy at risk is very high. In summer , the expected energy at risk is estimated to be 136 MWh. This figure is expected to rise to 146 MWh in summer , with a value to customers of around $9.2 million. 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. Contingency plans to transfer load to adjacent zone substations. Plans to transfer load to adjacent zone substations (DSH, MC and NP) at the distribution feeder level are established. These plans are reviewed annually prior to the summer season. Transfer capability away from KBH zone substation is assessed at 28.2 MVA for summer Install a second 66/22 kv transformer at KBH. In the absence of any lower-cost options, installation of another transformer at KBH is most likely the least cost, long term, technically feasible network option for addressing the limitations at KBH. 3. KBH is designed to accept the 20 MVA relocatable transformer. Review by: 12/2014 Page 130 of 309

132 Preferred network option(s) for alleviation of limitation UE proposes to implement contingency plans to transfer load quickly to adjacent zone substations for an unplanned outage of a transformer at KBH under critical loading conditions. Therefore, no major demand related augmentation is planned at KBH over the next five years. Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. KBH zone substation Summer cyclic N Rating (MVA) 45.0 Summer cyclic N-1 Rating (MVA) 0.0 Embedded generation capacity (MW) 0.0 KBH zone substation % PoE summer maximum demand (MVA) N/A Power factor N/A Number of hours where 95% of peak load is expected N/A Load transfer capability (MVA) N/A 28.2 N-1 energy at risk at 10% PoE demand (MWh) N/A 109, , , ,319 N-1 expected hours at risk at 10% PoE demand (hours) N/A 8,760 8,760 8,760 8,760 N-1 expected energy at risk at 10% PoE demand (kwh) N/A 136, , , ,065 Expected unserved energy at 10% PoE demand ($k) N/A 8, , , ,215.3 Review by: 12/2014 Page 131 of 309

133 Load (MVA) Strategy Lyndale zone substation Lyndale (LD) zone substation consists of three 20/30MVA 66/22kV transformers and supplies the areas of Dandenong, Dandenong North, Endeavour Hills and Rowville. UE installed a third 20/33 MVA transformer at LD zone substation in December Magnitude, probability and impact of loss of load LD is a summer-critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 55 Forecast maximum demand against station ratings for LD zone substation LD Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating A substantial amount of load has been transferred from Mulgrave (MGE) zone substation to LD after summer , as reflected in the graph above. The demand at LD zone substation is expected to exceed its (N-1) rating from summer However, the expected energy at risk is insignificant within the planning period. Therefore, no major demand related augmentation is planned at LD zone substation over the next five years. Review by: 12/2014 Page 132 of 309

134 Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. LD zone substation Summer cyclic N Rating (MVA) Summer cyclic N-1 Rating (MVA) 67.4 Embedded generation capacity (MW) 0.0 LD zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 35 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 133 of 309

135 Load (MVA) Strategy Langwarrin zone substation Langwarrin (LWN) zone substation consists of one 20/33 MVA 66/22 kv transformer and supplies the areas of Cranbourne South, Langwarrin and Pearcedale. LWN was commissioned in November 2009 to provide load relief for Frankston (FTN) and Frankston South (FSH) zone substations, as well as improving distribution feeder capacity and supply reliability in the area. As stated in previous planning reports, the load-at-risk at LWN is substantial and the load transfer capability is insufficient to manage the risk. Hence, UE has committed to installing a second 20/33 MVA 66/22 kv transformer at LWN. This project is expected to be commissioned by December Magnitude, probability and impact of loss of load LWN is a summer-critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 56 Forecast maximum demand against station ratings for LWN zone substation LWN Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating To date, the (N-1) rating at LWN zone substation is zero because it is a single transformer zone substation. LWN is reliant on distribution feeder transfer capability from adjacent zone substations to cater for an outage of the main transformer. UE therefore has installed remote controlled switches on every feeder to quickly transfer load supplied by LWN to adjacent zone substations and deployment of the relocatable transformer in the event of transformer outage during maximum Review by: 12/2014 Page 134 of 309

136 Expected Energy at Risk above N-1 (kwh) and Hours at Risk above N-1 (hrs) Customer value of lost load ($) Strategy demand periods. However, the transfer capacity is now depleting because of the demand growth at LWN and adjacent zone substations. Given the high demand, pre-summer load transfers were established to manage the loading of the LWN transformer during the last two summers. From summer onwards, the demand at LWN is expected to exceed the (N) rating. Given a steady demand growth over the next five years, a significant amount of energy would be at risk in the event of a forced transformer outage during maximum demand periods. However, the installation of the second transformer at LWN in December 2014 is expected to reduce this risk significantly. The figure below depicts the expected energy at risk with one transformer out-of-service for the 10% PoE demand forecast, and the hours per year that the 10% PoE demand forecast is expected to exceed the (N-1) station rating. The graph also shows the value to customers of the expected unserved energy in each year, for the 10% PoE demand forecast. Figure 57 Annual energy, hours at risk and expected customer value of lost load at LWN Magnitude of load at risk above (N-1) and value of lost load at LWN $16,000,000 $14,000, $12,000, $10,000,000 $8,000, $6,000, $4,000,000 $2,000, Year $0 Hours at risk above N-1 Expected energy above N-1 (kwhr) Customer value of lost load ($) Prior to commissioning the second transformer, the energy at risk is high at LWN for an outage of the existing transformer. Sub-transmission line circuit breakers are installed at LWN to prevent a single sub- transmission line fault tripping the zone substation transformer. Whilst the probability of a transformer failure is very low, the energy at risk resulting from a transformer fault is high, because customers supplied from this substation are exposed to such an event all year round. LWN has been designed to accept the 20 MVA relocatable transformer. Therefore the actual expected energy at risk before commissioning the second transformer is considerably lower than that indicated above. Review by: 12/2014 Page 135 of 309

137 Preferred network option(s) for alleviation of limitations The following operational measures are proposed to mitigate the risk of supply interruption until the second transformer is commissioned by December Establish pre-summer load transfers to FSH such that the LWN maximum demand is maintained within its cyclic (N) rating. 2. Maintain contingency plans to transfer load quickly to adjacent zone substations for an unplanned outage of the LWN transformer. Transfer capability away from LWN is assessed at 30.1 MVA for summer , which is insufficient to fully recover all LWN load for a failure of the LWN transformer. Given the available transfer capacity is insufficient to supply the total connected demand under extreme temperature conditions, the relocatable transformer will need to be deployed in the event of an emergency. Works are completed to allow the relocatable transformer to be connected at LWN should a major transformer fault occur. For summer it is proposed to manage the load at LWN with load transfers. Therefore, no major demand related augmentation is planned at LWN zone substation over the next five years, once the committed second transformer project is completed. Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. LWN zone substation Summer cyclic N Rating (MVA) 45.4 Summer cyclic N-1 Rating (MVA) 0.0 Embedded generation capacity (MW) 0.0 LWN zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 30.1 N-1 energy at risk at 10% PoE demand (MWh) 172, N-1 expected hours at risk at 10% PoE demand (hours) 8, N-1 expected energy at risk at 10% PoE demand (kwh) 214, Expected unserved energy at 10% PoE demand ($k) 13, Review by: 12/2014 Page 136 of 309

138 Load (MVA) Strategy 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 transformer was installed in December Magnitude, probability and impact of loss of load M is a summer-critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 58 Forecast maximum demand against station ratings for M zone substation M Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating The demand at M zone substation is expected to remain within its (N-1) rating for the next five years. Therefore, no major demand related augmentation is planned at M zone substation over the next five years. Review by: 12/2014 Page 137 of 309

139 Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. M zone substation Summer cyclic N Rating (MVA) 81.6 Summer cyclic N-1 Rating (MVA) 54.4 Embedded generation capacity (MW) 0.0 M zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 6.3 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 138 of 309

140 Load (MVA) Strategy 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. Part of MC is a very old substation which requires a rebuild to replace its assets. UE plans to replace the existing 20/27 MVA 66/22 kv transformers with 20/33 MVA 66/22 kv transformers by December UE also plans to replace the 22 kv outdoor switchgear with an indoor switchboard. Magnitude, probability and impact of loss of load MC is a summer-critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 59 Forecast maximum demand against station ratings for MC zone substation MC Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating MC has been operating above its (N-1) rating since summer With the commissioning of the new Keysborough (KBH) zone substation by December 2014, some load will be transferred away from MC to KBH. This transfer is reflected in the demand forecast as shown in the figure above. Despite this transfer, the maximum demand at MC zone substation is expected to exceed the station s (N-1) rating. The figure below depicts the expected energy at risk with one transformer out-of-service for the 10% PoE demand forecast, and the hours per year that the 10% PoE demand forecast is expected Review by: 12/2014 Page 139 of 309

141 Expected Energy at Risk above N-1 (kwh) and Hours at Risk above N-1 (hrs) Customer value of lost load ($) Strategy to exceed the (N-1) station rating. The graph also shows the value to customers of the expected unserved energy in each year, for the 10% PoE demand forecast. Figure 60 Annual energy, hours at risk and expected customer value of lost load at MC Magnitude of load at risk above (N-1) and value of lost load at MC 4500 $300, $250, $200, $150,000 $100, Year $50,000 $0 Hours at risk above N-1 Expected energy above N-1 (kwhr) Customer value of lost load ($) 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 summer for about 380 hours. It is emphasised however that the probability of a major outage of one of the transformers occurring over the duration of high load is very low. When the energy at risk is weighted by this low probability, the expected unserved energy is estimated to be 4,012 kwh in summer If no action is taken, this figure is expected to drop to 2,786 kwh in summer , with a value to customers of around $175.8k. Presently, there are no 66 kv line circuit breakers at MC zone substation. Therefore, a forced outage of one of the sub-transmission lines into MC zone substation would also lead to an outage of one of the MC zone substation transformer. In this case, the magnitude of the expected energy at risk would be much higher than the values presented above. 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. Contingency plans to transfer load to adjacent zone substations. Plans to transfer load to adjacent zone substations at the distribution feeder level are established. These plans are reviewed annually prior to the summer season. Transfer capability away from MC zone substation is assessed at 20.5 MVA for summer Works have been completed to allow the relocatable transformer to be connected should a major transformer fault occur. Review by: 12/2014 Page 140 of 309

142 2. Establish a new 66/22 kv zone substation. UE is constructing a new zone substation at Keysborough (KBH) by December Some load from MC can be transferred via Noble Park (NP) zone substation to KBH. However, just beyond the five year planning horizon it may also be necessary to establish a new zone substation around Moorabbin Airport in Mordialloc or Dingley to provide a longer term solution to the load limitation at MC. 3. Feeder load transfers. With the installation of a third transformer at Carrum (CRM) zone substation in 2009, some load was transferred from MC to CRM. Any further load transfer from MC to CRM is limited. Load transfers to Springvale South (SS) zone substation provide another option and SS has the potential to add a third 66/22 kv transformer if required. 4. Replace the existing MC transformers with new 20/33 MVA 66/22 kv transformers by December 2016 (as part of asset replacement). Preferred network option(s) for alleviation of limitations 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 until a long term solution is implemented. Once the new KBH zone substation is commissioned by December 2014, load can be transferred from MC onto KBH via NP. UE plans to replace the existing 20/27 MVA 66/22 kva transformers with 20/33 MVA 66/22 kv transformers by December Once commissioned, the station s rating would be adequate to meet the demand MC for the rest of this planning period. As a result, no major demand related augmentation is planned at MC zone substation over the next five years. Review by: 12/2014 Page 141 of 309

143 Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. MC zone substation Summer cyclic N Rating (MVA) 83.1 Summer cyclic N-1 Rating (MVA) 55.4 Embedded generation capacity (MW) 0.0 MC zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 20.5 N-1 energy at risk at 10% PoE demand (MWh) 1, N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) 4,012 2,259 2,490 2,686 2,786 Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 142 of 309

144 Load (MVA) Strategy 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. Magnitude, probability and impact of loss of load MGE is a summer-critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 61 Forecast maximum demand against station ratings for MGE zone substation MGE Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating With the exception of summer , the maximum demand at MGE zone substation has exceeded its (N-1) rating. The figure below depicts the expected energy at risk with one transformer out-of-service for the 10% PoE demand forecast, and the hours per year that the 10% PoE demand forecast is expected to exceed the (N-1) station rating. The graph also shows the value to customers of the expected unserved energy in each year, for the 10% PoE demand forecast. Review by: 12/2014 Page 143 of 309

145 Expected Energy at Risk above N-1 (kwh) and Hours at Risk above N-1 (hrs) Customer value of lost load ($) Strategy Figure 62 Annual energy, hours at risk and expected customer value of lost load at MGE Magnitude of load at risk above (N-1) and value of lost load at MGE 250 $14, $12,000 $10, $8, $6,000 $4, $2, Year $0 Hours at risk above N-1 Expected energy above N-1 (kwhr) Customer value of lost load ($) 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 summer for about 4 hours. It is emphasised however that the probability of a major outage of one of the transformers occurring over the duration of high load is very low. When the energy at risk is weighted by this low probability, the expected unserved energy is estimated to be 54 kwh in summer If no action is taken, this figure is expected to rise to 191 kwh in summer , with a value to customers of around $12.1k. To limit this risk, load can be transferred from MGE zone substation to Lyndale (LD) zone substation, where a third transformer was installed in December 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. Contingency plans to transfer load to adjacent zone substations. Plans to transfer load to adjacent zone substations at the distribution feeder level are established. These plans are reviewed annually prior to the summer season. Transfer capability away from MGE is assessed at 19 MVA for summer Establish a new 66/22 kv zone substation. There are no vacant zone substation sites in the area and the cost of acquiring a new site would very likely make such an option uneconomic when lower-cost alternatives are available. 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. This could also facilitate the growth and emerging limitations in SPI Electricity s areas of Knoxfield and Rowville. Review by: 12/2014 Page 144 of 309

146 Preferred network option(s) for alleviation of limitations UE proposes to implement contingency plans to transfer load quickly to adjacent zone substations for an unplanned outage of a transformer at MGE under critical loading conditions. Therefore, no major demand related augmentation is planned at MGE zone substation over the next five years. Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. MGE zone substation Summer cyclic N Rating (MVA) Summer cyclic N-1 Rating (MVA) 74.4 Embedded generation capacity (MW) 0.0 MGE zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 19.0 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 145 of 309

147 Load (MVA) Strategy Moorabbin zone substation Moorabbin (MR) zone substation consists of two 20/33 MVA 66/11 kv transformers and supplies the suburbs of Brighton, Hampton East and Moorabbin. Magnitude, probability and impact of loss of load MR is a summer-critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 63 Forecast maximum demand against station ratings for MR zone substation MR Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating The forecast demand at MR zone substation is expected to exceed its (N-1) rating from summer However, the expected energy at risk is insignificant within the planning period. Therefore, no major demand related augmentation is planned at MR zone substation over the next five years. Review by: 12/2014 Page 146 of 309

148 Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. MR zone substation Summer cyclic N Rating (MVA) 90.0 Summer cyclic N-1 Rating (MVA) 45.0 Embedded generation capacity (MW) 0.0 MR zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 9.0 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 147 of 309

149 Load (MVA) Strategy 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 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. Magnitude, probability and impact of loss of load MTN is a summer-critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 64 Forecast maximum demand against station ratings for MTN zone substation MTN Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating The demand at MTN zone substation is expected to exceed its (N-1) rating from summer The figure below depicts the expected energy at risk with one transformer out-of-service for the 10% PoE demand forecast, and the hours per year that the 10% PoE demand forecast is expected to exceed the (N-1) station rating. The graph also shows the value to customers of the expected unserved energy in each year, for the 10% PoE demand forecast. Review by: 12/2014 Page 148 of 309

150 Expected Energy at Risk above N-1 (kwh) and Hours at Risk above N-1 (hrs) Customer value of lost load ($) Strategy Figure 65 Annual energy, hours at risk and expected customer value of lost load at MTN Magnitude of load at risk above (N-1) and value of lost load at MTN 300 $20, $18,000 $16, Year $14,000 $12,000 $10,000 $8,000 $6,000 $4,000 $2,000 $0 Hours at risk above N-1 Expected energy above N-1 (kwhr) Customer value of lost load ($) As shown above, if there is a forced transformer outage during summer maximum demand periods, there will be insufficient capacity at MTN to supply all demand in summer for about 11 hours. It is emphasised however that the probability of a major outage of one of the transformers occurring over the duration of high load is very low. When the energy at risk is weighted by this low probability, the expected unserved energy is estimated to be 68 kwh in summer If no action is taken, this figure is expected to rise to 284 kwh in summer , with a value to customers of around $17.9k. 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. Contingency plans to transfer load to adjacent zone substations. Plans to transfer load to adjacent zone substations at the distribution feeder level are established. These plans are reviewed annually prior to the summer season. Transfer capability away from MTN is assessed at 10.2 MVA for summer Establish a new 66/22 kv zone substation. There are no vacant zone substation sites in the area and the cost of acquiring a new site would very likely make such an option uneconomic when lower-cost alternatives are available. 3. Install new transformation at an adjacent zone substation. A possible option is to install a second 66/22 kv transformer at DMA by December Some load from MTN can be transferred to DMA once this augmentation is taken place. Review by: 12/2014 Page 149 of 309

151 4. Install a third 20/33 MVA 66/22 kv transformer at MTN. In the absence of any lower-cost options, installation of another transformer at MTN is most likely the least cost, long term, technically feasible network option for addressing the limitation at MTN. Preferred network option(s) for alleviation of limitations 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. UE will monitor the demand in the area over the next couple of years before committing to any augmentation plans for MTN. A second transformer at Dromana (DMA) zone substation is likely to be required by December New distribution feeders would be constructed with the second transformer and they could potentially be used to offload MTN in the event the growth remains. As a result, no major demand related augmentation is planned at MTN zone substation over the next five years. Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. MTN zone substation Summer cyclic N Rating (MVA) 92.9 Summer cyclic N-1 Rating (MVA) 46.4 Embedded generation capacity (MW) 0.0 MTN zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 10.2 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 150 of 309

152 Load (MVA) Strategy 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. In 2012, UE replaced the transformers which were manufactured in the 1950s with new 20/33 MVA transformers. This has marginally increased the station rating as the rating is now limited by the 11 kv switchboard. UE plans to replace the 11 kv switchboard by December Once commissioned, the station s (N) and (N-1) rating is expected to increase by 10 MVA and 5 MVA respectively. Magnitude, probability and impact of loss of load NB is a summer-critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 66 Forecast maximum demand against station ratings for NB zone substation NB Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating NB has been operating above its (N-1) rating since summer Given a steady demand growth at NB, a substantial amount of energy will be at risk in the event of a transformer failure over the next five years. The figure below depicts the expected energy at risk with one transformer out-of-service for the 10% PoE demand forecast, and the hours per year that the 10% PoE demand forecast is expected Review by: 12/2014 Page 151 of 309

153 Expected Energy at Risk above N-1 (kwh) and Hours at Risk above N-1 (hrs) Customer value of lost load ($) Strategy to exceed the (N-1) station rating. The graph also shows the value to customers of the expected unserved energy in each year, for the 10% PoE demand forecast. Figure 67 Annual energy, hours at risk and expected customer value of lost load at NB Magnitude of load at risk above (N-1) and value of lost load at NB 140 $9, $8,000 $7,000 $6, $5, $4,000 $3,000 $2,000 $1, Year $0 Hours at risk above N-1 Expected energy above N-1 (kwhr) Customer value of lost load ($) 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 summer for about 7 hours. It is emphasised however that the probability of a major outage of one of the transformers occurring over the duration of high load is very low. When the energy at risk is weighted by this low probability, the expected unserved energy is estimated to be 68 kwh in summer If no action is taken, this figure is expected to rise to 122 kwh in summer , with a value to customers of around $7.7k. 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. Contingency plans to transfer load to adjacent zone substations. Plans to transfer load to adjacent zone substations at the distribution feeder level are established. These plans are reviewed annually prior to the summer season. Transfer capability away from NB zone substation is assessed at 14.2 MVA for summer Establish a new 66/11 kv zone substation. There are no sites under consideration to be developed as a new zone substation to offload NB. Review by: 12/2014 Page 152 of 309

154 3. Replace the 11 kv switchboard. In the absence of any lower-cost options, replacing the 11kV switchboard at NB is most likely the least cost technically feasible network option for addressing the limitations at NB. Preferred network option(s) for alleviation of limitations UE proposes to implement contingency plans to transfer load quickly to adjacent zone substations for an unplanned outage of a transformer at NB under critical loading conditions. Following the replacement of the aged switchboard with new, modern equivalent switchboard by December 2016, no major demand related augmentation is planned at NB over the next five years. Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. NB zone substation Summer cyclic N Rating (MVA) 79.6 Summer cyclic N-1 Rating (MVA) 39.8 Embedded generation capacity (MW) 0.0 NB zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 14.2 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 153 of 309

155 Load (MVA) Strategy 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. Magnitude, probability and impact of loss of load NO is a summer-critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 68 Forecast maximum demand against station ratings for NO zone substation NO Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating NO has been operating above its (N-1) rating since summer Given a steady demand growth at NO, a substantial amount of energy will be at risk in the event of a transformer failure over the next five years. With the movement of the relocation transformer from Dandenong Valley (DVY) to Clarinda (CDA), some load has been transferred from NO to CDA to minimise this risk. The figure below depicts the expected energy at risk with one transformer out-of-service for the 10% PoE demand forecast, and the hours per year that the 10% PoE demand forecast is expected to exceed the (N-1) station rating. The graph also shows the value to customers of the expected unserved energy in each year, for the 10% PoE demand forecast. Review by: 12/2014 Page 154 of 309

156 Expected Energy at Risk above N-1 (kwh) and Hours at Risk above N-1 (hrs) Customer value of lost load ($) Strategy Figure 69 Annual energy, hours at risk and expected customer value of lost load at NO Magnitude of load at risk above (N-1) and value of lost load at NO 600 $40, $35,000 $30, $25, $20, $15,000 $10, $5, Year $0 Hours at risk above N-1 Expected energy above N-1 (kwhr) Customer value of lost load ($) 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 summer for about 48 hours. It is emphasised however that the probability of a major outage of one of the transformers occurring over the duration of high load is very low. When the energy at risk is weighted by this low probability, the expected unserved energy is estimated to be 310 kwh in summer If no action is taken, this figure is expected to rise to 544 kwh in summer , with a value to customers of around $34.4k. Presently, there are no 66 kv line circuit breakers at NO zone substation. Therefore, a forced outage of one of the sub-transmission lines into NO zone substation would also lead to an outage of one of the NO zone substation transformers. Therefore, the magnitude of the expected energy at risk would be much higher than the values presented above. 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. Contingency plans to transfer load to adjacent zone substations. Plans to transfer load to adjacent zone substations at the distribution feeder level are established. These plans are reviewed annually prior to the summer season. Transfer capability away from NO is assessed at 21.8 MVA for summer Establish a new 66/22 kv zone substation. There are no vacant zone substation sites in the area and the cost of acquiring a new site would very likely make such an option uneconomic when lower-cost options are available. Review by: 12/2014 Page 155 of 309

157 3. Install a third 66/22 kv transformer at NO by December In the absence of any vacant site, installation of another transformer at NO is most likely the least cost technically feasible network option for the long term. 4. Demand reduction, in the order of 6 MW or more in December 2017, connected within NO/SV/SVW supply areas, can defer the need for augmentation at NO zone substation. UE has developed a number of innovative network tariffs that encourage voluntary demand reduction during times of network limitation. The amount of demand reduction depends on the tariff uptake and will be taken into consideration when determining the optimum timing for the capacity augmentation. 5. Embedded generation, in the order of 6 MW or more in December 2017, connected within the NO/SV/SVW supply areas, can defer the need for augmentation at NO zone substation. Preferred network option(s) for alleviation of limitations UE proposes to implement contingency plans to transfer load quickly to adjacent zone substations for an unplanned outage of a transformer at NO under critical loading conditions. As a means of managing the risk at NO and neighbouring SV/SVW zone substations, UE plans to install a third transformer at NO by December 2017, at an estimated cost of $7 million. This plan will be undertaken in the absence of any commitment by interested parties to offer network support services through demand side management initiatives that would reduce load at NO. The estimated total annual cost of the preferred network option is $700,000. This cost provides a broad upper bound indication of the maximum contribution from UE which may be available to non-network service providers to reduce forecast demand and defer or avoid this augmentation. UE invites non-network service providers to submit their proposals to alleviate limitations at Notting Hill (NO) zone substation. Review by: 12/2014 Page 156 of 309

158 Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. NO zone substation Summer cyclic N Rating (MVA) 74.0 Summer cyclic N-1 Rating (MVA) 37.0 Embedded generation capacity (MW) 0.0 NO zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 21.8 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 157 of 309

159 Load (MVA) Strategy 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. Magnitude, probability and impact of loss of load NP is a summer-critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 70 Forecast maximum demand against station ratings for NP zone substation NP Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating With the exception of the last two summers, the maximum demand at NP has exceeded its (N-1) rating. The demand at NP has reduced last summer as a result of load transfer to Lyndale (LD) zone substation after commissioning the third LD transformer. It is expected that further load will be transferred from NP to the new Keysborough (KBH) zone substation which is expected to be commissioned in December Following this transfer, the maximum demand at NP is expected to drop below its (N-1) rating, as reflected in the figure above. Therefore, no energy at risk is anticipated at NP beyond summer Review by: 12/2014 Page 158 of 309

160 Preferred network option(s) for alleviation of limitations Until KBH is commissioned, UE proposes to maintain contingency plans to transfer load quickly to adjacent zone substations for an unplanned outage of a transformer at NP under critical loading conditions. The transfer capability away from NP is assessed at 22.6 MVA for summer Distribution feeder works shall be used to transfer some load from NP when the new KBH zone substation is commissioned by December Therefore, no major demand related augmentation is planned at NP zone substation over the next five years. Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. NP zone substation Summer cyclic N Rating (MVA) Summer cyclic N-1 Rating (MVA) 72.0 Embedded generation capacity (MW) 0.0 NP zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 22.6 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 159 of 309

161 Load (MVA) Strategy Nunawading zone substation Nunawading (NW) 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 areas of Blackburn, Donvale and Nunawading. Magnitude, probability and impact of loss of load NW is a summer-critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 71 Forecast maximum demand against station ratings for NW zone substation NW Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating The forecast demand at NW zone substation is expected to exceed its (N-1) rating from summer The energy at risk is expected to be insignificant within the planning period. Therefore, no major demand related augmentation is planned at NW zone substation over the next five years. Review by: 12/2014 Page 160 of 309

162 Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. NW zone substation Summer cyclic N Rating (MVA) Summer cyclic N-1 Rating (MVA) 67.4 Embedded generation capacity (MW) 0.0 NW zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 19.7 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 161 of 309

163 Load (MVA) Strategy Oakleigh zone substation Oakleigh (OAK) zone substation consists of two 20/33 MVA 66kV/11 kv transformers and supplies the areas of Chadstone and Oakleigh. One of the transformers is a relocatable 66/11 kv transformer that is nominated to be used at another 66/11 kv zone substation following a major transformer fault at a critical zone substation. Being a designated Principal Activities Centre, the maximum demand around the Chadstone area is expected to continue to grow steadily. Magnitude, probability and impact of loss of load OAK is a summer-critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 72 Forecast maximum demand against station ratings for OAK zone substation OAK Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating The forecast demand at OAK zone substation is expected to exceed its (N-1) rating from summer The energy at risk is expected to be insignificant within the planning period. Therefore, no major demand related augmentation is planned at OAK zone substation over the next five years. Review by: 12/2014 Page 162 of 309

164 Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. OAK zone substation Summer cyclic N Rating (MVA) 87.2 Summer cyclic N-1 Rating (MVA) 43.6 Embedded generation capacity (MW) 0.0 OAK zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 8.4 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 163 of 309

165 Load (MVA) Strategy 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. Magnitude, probability and impact of loss of load OE is a summer critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 73 Forecast maximum demand against station ratings for OE zone substation OE Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating The demand at OE zone substation is expected to remain within its (N-1) rating for the next five years. Therefore, no major demand related augmentation is planned at OE zone substation over the next five years. Review by: 12/2014 Page 164 of 309

166 Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. OE zone substation Summer cyclic N Rating (MVA) 64.8 Summer cyclic N-1 Rating (MVA) 32.4 Embedded generation capacity (MW) 0.0 OE zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 4.2 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 165 of 309

167 Load (MVA) Strategy 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. Magnitude, probability and impact of loss of load OR is a summer-critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 74 Forecast maximum demand against station ratings for OR zone substation OR Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating During summer , the maximum demand at OR exceeded the station s (N-1) rating. Given a steady demand growth at OR, a substantial amount of energy will be at risk in the event of a transformer failure over the next five years. The figure below depicts the expected energy at risk with one transformer out-of-service for the 10% PoE demand forecast, and the hours per year that the 10% PoE demand forecast is expected to exceed the (N-1) station rating. The graph also shows the value to customers of the expected unserved energy in each year, for the 10% PoE demand forecast. Review by: 12/2014 Page 166 of 309

168 Expected Energy at Risk above N-1 (kwh) and Hours at Risk above N-1 (hrs) Customer value of lost load ($) Strategy Figure 75 Annual energy, hours at risk and expected customer value of lost load at OR Magnitude of load at risk above (N-1) and value of lost load at OR 450 $30, $25, $20, $15, $10, $5, Year $0 Hours at risk above N-1 Expected energy above N-1 (kwhr) Customer value of lost load ($) 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 summer for about 20 hours. It is emphasised however that the probability of a major outage of one of the transformers occurring over the duration of high load is very low. When the energy at risk is weighted by this low probability, the expected unserved energy is estimated to be 78 kwh in summer If no action is taken, this figure is expected to rise to 401 kwh in summer , with a value to customers of around $25.3k. 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. Contingency plans to transfer load to adjacent zone substations. Plans to transfer load to adjacent zone substations at the distribution feeder level are established. These plans are reviewed annually prior to the summer season. Transfer capability away from OR is assessed at 8.5 MVA for summer Establish a new 66/11 kv zone substation. There are no sites under consideration to be developed as a new zone substation to offload OR. 3. Install a third 66/11 kv transformer at OR. In the absence of any lower-cost options, installation of another transformer at OR is most likely the least cost technically feasible network option for addressing the limitations at OR. Review by: 12/2014 Page 167 of 309

169 4. Replace the existing OR transformers with 20/33 MVA 66/11 kv transformers by December 2020 (as an asset replacement project). Preferred network option(s) for alleviation of limitations UE proposes to implement contingency plans to transfer load quickly to adjacent zone substations for an unplanned outage of a transformer at OR under critical loading conditions. As a result, no major demand related augmentation is planned at OR zone substation over the next five years. Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. OR zone substation Summer cyclic N Rating (MVA) 64.6 Summer cyclic N-1 Rating (MVA) 32.3 Embedded generation capacity (MW) 0.0 OR zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 8.5 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 168 of 309

170 Load (MVA) Strategy Rosebud zone substation Rosebud (RBD) zone substation consists of two 20/33 MVA 66/22 kv transformers and supplies the areas of Arthur s 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 Magnitude, probability and impact of loss of load RBD is a summer-critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 76 Forecast maximum demand against station ratings for RBD zone substation RBD Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating The demand at RBD zone substation is expected to exceed its (N-1) rating from summer The figure below depicts the expected energy at risk with one transformer out-of-service for the 10% PoE demand forecast, and the hours per year that the 10% PoE demand forecast is expected to exceed the (N-1) station rating. The graph also shows the value to customers of the expected unserved energy in each year, for the 10% PoE demand forecast. Review by: 12/2014 Page 169 of 309

171 Expected Energy at Risk above N-1 (kwh) and Hours at Risk above N-1 (hrs) Customer value of lost load ($) Strategy Figure 77 Annual energy, hours at risk and expected customer value of lost load at RBD Magnitude of load at risk above (N-1) and value of lost load at RBD 30 $1, $1,600 $1, $1, $1,000 $800 $ Year $400 $200 $0 Hours at risk above N-1 Expected energy above N-1 (kwhr) Customer value of lost load ($) 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 summer for about 2 hours. It is emphasised however that the probability of a major outage of one of the transformers occurring over the duration of high load is very low. When the energy at risk is weighted by this low probability, the expected unserved energy is estimated to be 3 kwh in summer If no action is taken, this figure is expected to rise to 26 kwh in summer , with a value to customers of around $1.6k. 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. Contingency plans to transfer load to adjacent zone substations. Plans to transfer load to adjacent zone substations at the distribution feeder level are established. These plans are reviewed annually prior to the summer season. Transfer capability away from RBD is assessed at 14.7 MVA for summer Establish a new 66/22 kv zone substation. There are no sites under consideration to be developed as a new zone substation to offload RBD. 3. Install a second 66/22 kv transformer at DMA and establish distribution feeder works to transfer load away from RBD. 4. Install a third 66/22kV transformer at RBD. Review by: 12/2014 Page 170 of 309

172 Preferred network option(s) for alleviation of limitations UE proposes to maintain contingency plans to transfer load quickly to adjacent zone substations for an unplanned outage of a transformer at RBD under critical loading conditions. Therefore, no major demand related augmentation is planned at RBD zone substation over the next five years. Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. RBD zone substation Summer cyclic N Rating (MVA) 91.6 Summer cyclic N-1 Rating (MVA) 45.8 Embedded generation capacity (MW) 0.0 RBD zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 14.7 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 171 of 309

173 Load (MVA) Strategy Surrey Hills zone substation Surrey Hills (SH) zone substation consists of two 10 MVA 22kV/6.6 kv transformers and supplies Surrey Hills. SH is a very old substation and UE reviewed the condition of the entire SH network in Based on the review, UE is in the process of replacing 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. Magnitude, probability and impact of loss of load SH is a summer-critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 78 Forecast maximum demand against station ratings for SH zone substation SH Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating The demand at SH zone substation is expected to remain within its (N-1) rating for the next five years. Therefore, no major demand related augmentation is planned at SH zone substation over the next five years. The long term plan for this station will be based on the strategic plan which is being currently developed for the area. Review by: 12/2014 Page 172 of 309

174 Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. SH zone substation Summer cyclic N Rating (MVA) 21.6 Summer cyclic N-1 Rating (MVA) 10.8 Embedded generation capacity (MW) 0.0 SH zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 0.0 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 173 of 309

175 Load (MVA) Strategy 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. Magnitude, probability and impact of loss of load SR is a summer-critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 79 Forecast maximum demand against station ratings for SR zone substation SR Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating The forecast demand at SR zone substation is expected exceed its (N-1) rating from summer However, the expected energy at risk is insignificant within the planning period. Therefore, no major demand related augmentation is planned at SR zone substation over the next five years. Review by: 12/2014 Page 174 of 309

176 Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. SR zone substation Summer cyclic N Rating (MVA) 73.1 Summer cyclic N-1 Rating (MVA) 36.5 Embedded generation capacity (MW) 0.0 SR zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 11.1 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 175 of 309

177 Load (MVA) Strategy 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 by approximately 7 MW on weekdays between 7:00 am and 11:00 pm. UE does not currently have network support agreements with these generators. Magnitude, probability and impact of loss of load SS is a summer-critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 80 Forecast maximum demand against station ratings for SS zone substation SS Summer Maximum Demand Year Actual Load with Generation Summer (N) Rating Actual Load without Generation Forecast Load with Generation Summer (N-1) Rating Forecast Load without Generation With the embedded generation, the demand at SS zone substation is expected to exceed its (N-1) rating from summer The figure below depicts the expected energy at risk with one transformer out-of-service for the 10% PoE demand forecast, and the hours per year that the 10% PoE demand is forecast is expected to exceed the (N-1) station rating. The graph also shows the value to customers of the expected unserved energy in each year, for the 10% PoE demand forecast. Review by: 12/2014 Page 176 of 309

178 Expected Energy at Risk above N-1 (kwh) and Hours at Risk above N-1 (hrs) Customer value of lost load ($) Strategy Figure 81 Annual energy, hours at risk and expected customer value of lost load at SS Magnitude of load at risk above (N-1) and value of lost load at SS Including Generation 10 $ $ Year $500 $400 $300 $200 $100 $0 Hours at risk above N-1 Expected energy above N-1 (kwhr) Customer value of lost load ($) As shown above, if there is a forced transformer outage during summer maximum demand periods, there will be insufficient capacity at SS zone substation to supply all demand in summer for about 2 hours. It is emphasised however that the probability of a major outage of one of the transformers occurring over the duration of high load is very low. When the energy at risk is weighted by this low probability, the expected energy at risk is estimated to be 2 kwh in summer If no action is taken, this figure is expected to rise to 9 kwh in summer , with a value to customers of around $0.6k. In the absence of the embedded generation, the expected energy at risk is estimated to be to be 31 kwh in summer If no action is taken, this figure is expected to rise to 74 kwh in summer , with a value to customers of around $4.7k. 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. Contingency plans to transfer load to adjacent zone substations. Plans to transfer load to adjacent zone substations at the distribution feeder level are established. These plans are reviewed annually prior to the summer season. Transfer capability away from SS is assessed at 23.6 MVA for summer Establish a new 66/22 kv zone substation. There presently no sites under consideration planned to be developed as a new zone substation to offload SS. However, just beyond the five year planning horizon it may be necessary to establish a new zone substation Review by: 12/2014 Page 177 of 309

179 around Moorabbin Airport in Mordialloc or Dingley to provide a longer term solution to the load limitations at MC and SS. 3. Install a third 66/22 kv transformer at SS. In the absence of any lower-cost options, installation of another transformer at SS is most likely the least cost technically feasible network option for addressing the limitations at SS. This option will allow transferring a substantial amount of load away from MC, which is heavily loaded, to SS. 4. Enter into a network support agreement with the embedded generator connected to SS zone substation to reduce the energy at risk once it becomes more significant. Preferred network option(s) for alleviation of limitations 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. In the 2012 DSPR, UE identified the third 66/22 kv transformer at SS by December 2017 as the preferred long term solution for alleviating limitations at SS and neighbouring Mordialloc (MC) zone substation. Given a significant reduction in growth forecasts of maximum demand at SS, this option is no longer required within this planning period. UE plans to rebuild the ageing Mordialloc (MC) zone substation by December 2016, which is expected to increase the rating of MC. Once rebuilt, distribution feeders shall be used to offload SS zone substation onto MC zone substation. Therefore, no major demand related augmentation is planned at SS zone substation over the next five years. Review by: 12/2014 Page 178 of 309

180 Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. SS zone substation Summer cyclic N Rating (MVA) 80.2 Summer cyclic N-1 Rating (MVA) 40.1 Embedded generation capacity (MW) 7.0 SS zone substation (With generation) % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 23.6 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 179 of 309

181 Load (MVA) Strategy 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. Magnitude, probability and impact of loss of load STO is a summer-critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 82 Forecast maximum demand against station ratings for STO zone substation STO Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating STO has been operating above its (N-1) rating since and the demand is expected to grow continuously over time. The figure below depicts the expected energy at risk with one transformer out-of-service for the 10% PoE demand forecast, and the hours per year that the 10% PoE demand forecast is expected to exceed the (N-1) station rating. The graph also shows the value to customers of the expected unserved energy in each year, for the 10% PoE demand forecast. Review by: 12/2014 Page 180 of 309

182 Expected Energy at Risk above N-1 (kwh) and Hours at Risk above N-1 (hrs) Customer value of lost load ($) Strategy Figure 83 Annual energy, hours at risk and expected customer value of lost load at STO Magnitude of load at risk above (N-1) and value of lost load at STO 80 $5, $4,500 $4,000 $3,500 $3, Year $2,500 $2,000 $1,500 $1,000 $500 $0 Hours at risk above N-1 Expected energy above N-1 (kwhr) Customer value of lost load ($) 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 summer for about 3 hours. It is emphasised however that the probability of a major outage of one of the transformers occurring over the duration of high load 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 summer If no action is taken, this figure is expected to rise to 72 kwh in summer , with a value to customers of around $4.5k. 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. Contingency plans to transfer load to adjacent zone substations. Plans to transfer load to adjacent zone substations at the distribution feeder level are established. These plans are reviewed annually prior to the summer season. Transfer capability away from STO is assessed at 11.5 MVA for summer Establish a new 66/22 kv zone substation. There are no sites under consideration to be developed as a new zone substation to offload STO. 3. Install a third 66/22 kv transformer at STO. In the absence of any lower-cost options, installation of another transformer at STO is most likely the least cost technically feasible network option for addressing the limitations at STO at some time in the future. Review by: 12/2014 Page 181 of 309

183 Preferred network option(s) for alleviation of limitations UE proposes to maintain contingency plans to transfer load quickly to adjacent zone substations for an unplanned outage of a transformer at STO under critical loading conditions. Therefore, no major demand related augmentation is planned at STO zone substation over the next five years. Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. STO zone substation Summer cyclic N Rating (MVA) 72.0 Summer cyclic N-1 Rating (MVA) 36.0 Embedded generation capacity (MW) 0.0 STO zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 11.5 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 182 of 309

184 Load (MVA) Strategy 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 transformers, one 22 kv capacitor bank and two 22 kv buses. 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 supply the areas of Springvale, Clayton and the Monash University precinct in Clayton North. Magnitude, probability and impact of loss of load SV and SVW are summer-critical zone substations. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 84 Forecast maximum demand against station ratings for SV and SVW zone substations SV/SVW Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating The forecast demand at SV/SVW zone substation is expected exceed the (N-1) rating from summer Review by: 12/2014 Page 183 of 309

185 Expected Energy at Risk above N-1 (kwh) and Hours at Risk above N-1 (hrs) Customer value of lost load ($) Strategy The figure below depicts the expected energy at risk with one transformer out-of-service for the 10% PoE demand forecast, and the hours per year that the 10% PoE demand forecast is expected to exceed the (N-1) station rating. The graph also shows the value to customers of the expected unserved energy in each year, for the 10% PoE demand forecast. Figure 85 Annual energy, hours at risk and expected customer value of lost load at SV and SVW Magnitude of load at risk above (N-1) and value of lost load at SV/SVW 700 $45, $40,000 $35,000 $30, $25, $20,000 $15,000 $10,000 $5, Year $0 Hours at risk above N-1 Expected energy above N-1 (kwhr) Customer value of lost load ($) As shown above, if there is a forced transformer outage during summer maximum demand periods, there will be insufficient capacity at SV/SVW zone substations to supply all demand in summer for about 6 hours. It is emphasised however that the probability of a major outage of one of the transformers occurring over the duration of high load is very low. When the energy at risk is weighted by this low probability, the expected energy at risk is estimated to be 126 kwh in summer If no action is taken, this figure is expected to rise to 629 kwh in summer , with a value to customers of around $39.7k. Presently, there are no 66 kv line circuit breakers at SV/SVW zone substations. Therefore, a forced outage of one of the sub-transmission lines into SV/SVW zone substations would also lead to an outage of one transformer at SV or SVW zone substations. In this case, the magnitude of the expected energy at risk would be higher than the values presented above. SV and SVW supply a number of customers with high security requirements and these customers have a dual supply with primary and backup supplies from independent 22kV 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 18.9 MVA and SVW 11.5 MVA for summer Review by: 12/2014 Page 184 of 309

186 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. Contingency plans to transfer load to adjacent zone substations. Plans to transfer load to adjacent zone substations at the distribution feeder level are established. These plans are reviewed annually prior to the summer season. Transfer capability away from SV and SVW is assessed at 20.4 MVA for summer Establish a new 66/22 kv zone substation. There are no vacant zone substation sites in the area and the cost of acquiring a new site would very likely make such an option uneconomic. 3. Install a third 66/22 kv transformer at NO, SVW or SV. In the absence of any vacant site, installation of 3 rd transformer at NO is most likely the least cost technically feasible network option for the long term with load transfers from SV and SVW to NO. Preferred network option(s) for alleviation of limitations UE proposes to maintain contingency plans to transfer load quickly to adjacent zone substations for an unplanned outage of a transformer at SV and SVW under critical loading conditions. In the 2012 DSPR, UE identified the third 66/22 kv transformer at SV or SVW zone substation by December 2015 as the preferred long term solution for alleviating limitations at SV and SVW zone substations. UE has reassessed the demand forecasts and assessed that the additional transformer would best be placed at neighbouring Notting Hill (NO) zone substation by December Once commissioned, distribution feeders shall be used to manage loading at SV and SVW zone substations. Therefore, no major demand related augmentation is planned at SV/SVW zone substations over the next five years. Review by: 12/2014 Page 185 of 309

187 Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. SV/SVW zone substation Summer cyclic N Rating (MVA) Summer cyclic N-1 Rating (MVA) Embedded generation capacity (MW) 0.0 SV/SVW zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 20.4 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 186 of 309

188 Load (MVA) Strategy West Doncaster zone substation West Doncaster (WD) zone substation is fully developed with three 20/27 MVA 66/11 kv transformers and supplies the areas of Balwyn, Doncaster and the Doncaster Hill precinct. Magnitude, probability and impact of loss of load WD is a summer-critical zone substation. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the station s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 86 Forecast maximum demand against station ratings for WD zone substation WD Summer Maximum Demand Year Actual Load Forecast Load Summer (N) Rating Summer (N-1) Rating The demand at WD zone substation is expected to remain within its (N-1) rating for the next five years. Therefore, no major demand related augmentation is planned at WD zone substation over the next five years. Review by: 12/2014 Page 187 of 309

189 Station summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. WD zone substation Summer cyclic N Rating (MVA) 94.9 Summer cyclic N-1 Rating (MVA) 63.3 Embedded generation capacity (MW) 0.0 WD zone substation % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 6.1 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 188 of 309

190 6.9.2 Sub-transmission systems 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-LWN-FTN-FTS-CBTS. CBTS-CRM-LWN-FTN-FTS-CBTS The CBTS-CRM-LWN-FTN-FTS-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 SPI PowerNet. Figure 87 CBTS-CRM-LWN-FTN-FTS-CBTS sub-transmission system CBTS FTS CRM FTN LWN In 2009, LWN zone substation was inserted into this sub-transmission system. As part of the LWN zone substation project, this sub-transmission system was upgraded to increase the (N) and (N-1) ratings. Review by: 12/2014 Page 189 of 309

191 The ownership of the 66 kv assets supplying CRM, FTN and LWN zone substations is listed in the table below. Table 15 Network ownership arrangement 66 kv lines Ownership CBTS-FTS No.1 line CBTS-FTS No.2 line CBTS-CRM line FTS-FTN line FTS-LWN line CRM-FTN-LWN line Transmission connection asset owned by SPI PowerNet Transmission connection asset owned by SPI PowerNet Distribution asset owned by UE Distribution asset owned by UE Distribution asset owned by UE 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. If the ratings of the CBTS-FTS 66 kv lines are exceeded, SPI PowerNet s automatic load shedding scheme would be initiated to trip both lines. This will 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. Magnitude, probability and impact of loss of load CBTS-CRM-LWN-FTN-FTS-CBTS is a summer-critical sub-transmission system. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the system s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Review by: 12/2014 Page 190 of 309

192 Load (A) Strategy Figure 88 Forecast maximum demand against the CBTS-CRM-LWN-FTN-FTS-CBTS system ratings CBTS-CRM-LWN-FTN-FTS-CBTS Year Actual Load Forecast Load Summer (N-1) rating Summer (N) rating The demand on the CBTS-CRM-LWN-FTN-FTS-CBTS sub-transmission system is expected to exceed its (N-1) rating from summer The figure below depicts the expected energy at risk with the CBTS-CRM 66 kv line out-of-service for the 10% PoE maximum demand forecast, and the hours per year that the 10% PoE maximum demand is forecast is expected to exceed the (N-1) system rating. The graph also shows the value to customers of the expected unserved energy in each year, for the 10% PoE maximum demand forecast. Review by: 12/2014 Page 191 of 309

193 Expected Energy at Risk above N-1 (kwh) and Hours at Risk above N-1 (hrs) Customer value of lost load ($) Strategy Figure 89 Annual energy, hours at risk and expected customer value of lost load Magnitude of load at risk above (N-1) and value of lost load at CBTS- CRM-FTN-LWN-FTS-CBTS 3000 $180, $160,000 $140, Year $120,000 $100,000 $80,000 $60,000 $40,000 $20,000 $0 Hours at risk above N-1 (hours) Expected energy above N-1 (kwhr) Customer value of lost load ($) As shown above, if there is an outage of the CBTS-CRM 66 kv line during summer maximum demand periods, there will be insufficient capacity on the system to supply all demand in Given the limited section of this sub-transmission system is owned and operated by SPI PowerNet, the CBTS-FTS 66 kv lines would be disconnected by SPI PowerNet which can result in loss of electricity supply to all customers connected at CRM, FTN and LWN zone substations. In such an event, it is expected that the CBTS-FTS 66 kv lines can be re-energised within two hours after ensuring sufficient demand reduction to avoid further overloading. The total estimated duration of the limitation for summer is about 4 hours. It is emphasised however that the probability of a major outage of the CBTS-CRM 66 kv line occurring over the duration of high load is very low. Therefore, the expected energy at risk is estimated at 267 kwh in summer If no action is taken, this figure is expected to rise to 2,702 kwh in summer , with a value to customers of around $170.5k. 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. Implement a contingency plan to transfer load to adjacent sub-transmission systems and the use of dynamic line ratings. UE has established and implemented the necessary plans that enable load transfers under contingency conditions, via both 66 kv sub-transmission and 22 kv distribution networks. These plans are reviewed annually prior to the summer season. Transfer capability away from this sub-transmission system is assessed at 32.2 MVA for summer Review by: 12/2014 Page 192 of 309

194 2. Upgrade CBTS-FTS No.1 and CBTS-FTS No.2 66 kv circuits. The preliminary assessments revealed that this option would require complete rebuilding of these two lines as the existing assets are not designed to carry additional mechanical load. 3. Establish a new 66 kv line out of CBTS to augment the existing 66 kv loop. 4. Establish a new 66 kv loop from CBTS to supply a new 66/22 kv zone substation in the Skye/Carrum Downs area and offload the existing 66 kv loop. Preferred network option(s) for alleviation of limitations UE proposes to maintain its existing contingency plans that include dynamic ratings and load transfers to adjacent sub-transmission systems for an unplanned outage of the CBTS-CRM 66 kv line under critical loading conditions until a long term solution is implemented. As a means of managing the increasing risk on this sub-transmission system, UE proposes to establish a new 66 kv loop from CBTS to supply a new 66/22 kv zone substation in the Skye/Carrum Downs area and offload the existing 66 kv system. This augmentation is not likely before December Therefore, no major demand related augmentation is planned for this system over the next five years. System summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. CBTS-CRM-FTN-LWN-FTS-CBTS system Summer cyclic N Rating (MVA) Summer cyclic N-1 Rating (MVA) Embedded generation capacity (MW) 0.0 CBTS-CRM-FTN-LWN-FTS-CBTS system % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 32.2 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) ,409 2,268 2,702 Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 193 of 309

195 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-HPK/DSH-DVY-ERTS. 2. ERTS-MGE-LD-ERTS. ERTS-DN-HPK/DSH-DVY-ERTS The ERTS-DN-HPK/DSH-DVY-ERTS sub-transmission system is a shared system between UE and SPI Electricity (SPIE) that supplies Dandenong (DN), Dandenong South (DSH) and Dandenong Valley (DVY) zone substations as well as SPIE s Hampton Park (HPK) zone substation as shown below. Planning on this system is therefore a joint responsibility. Embedded generation in the area helps to reduce demand at DN and HPK zone substations by approximately 5 MW and 6.6 MW respectively. Figure 90 ERTS-DN-HPK/DSH-DVY-ERTS sub-transmission system ERTS HPK DSH DN DVY Prior to 2010, ERTS-DN-HPK-ERTS and ERTS-DSH-DVY-ERTS were two independent subtransmission systems. Due to capacity limitations on both systems, UE established a 66 kv tieline 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 SPIE in December 2012 to provide a long-term solution for both systems. Review by: 12/2014 Page 194 of 309

196 The ownership of the 66 kv assets supplying DN, DSH, DVY and HPK zone substations are listed in the table below. Table 16 Network ownership arrangement 66 kv lines Ownership ERTS-DN line ERTS-DSH line ERTS-DVY line ERTS-HPK line ERTS-HPK-DN line DN-DSH-DVY line Distribution asset owned by UE Distribution asset owned by UE Distribution asset owned by UE Distribution asset owned by SPIE Distribution asset owned by UE between DN and HPK Distribution asset owned by SPIE between ERTS and the tee point Distribution asset owned by UE The critical section on this sub-transmission system is currently the ERTS-DN 66 kv line for an outage of the ERTS-DSH 66kV line. Magnitude, probability and impact of loss of load ERTS-DN-HPK/DSH-DVY-ERTS is a summer-critical sub-transmission system. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the system s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Review by: 12/2014 Page 195 of 309

197 Load (A) Strategy Figure 91 Forecast maximum demand against the ERTS-DN-HPK/DSH-DVY-ERTS system ratings ERTS-DN-HPK/DSH-DVY-ERTS Year Actual Load with Generation Forecast Load with Generation Summer (N-1) rating Summer (N) rating Actual Load without Generation Forecast Load without Generation The demand on the ERTS-DN-HPK/DSH-DVY-ERTS sub-transmission system is expected to remain within its (N-1) rating for the next five years. Therefore, no major demand related augmentation is planned for this system over the next five years. Review by: 12/2014 Page 196 of 309

198 System summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. ERTS-DSH-DVY-DN-HPK-ERTS system Summer cyclic N Rating (MVA) Summer cyclic N-1 Rating (MVA) Embedded generation capacity (MW) 11.6 ERTS-DSH-DVY-DN-HPK-ERTS system (With generation) % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 22 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 197 of 309

199 Load (A) Strategy ERTS-MGE-LD-ERTS ERTS-MGE-LD-ERTS 66kV sub-transmission system supplies Mulgrave (MGE) and Lyndale (LD) 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. Similarly, for an outage of the ERTS-MGE 66 kv line, the ERTS-LD 66 kv line is constrained. Magnitude, probability and impact of loss of load ERTS-MGE-LD-ERTS is a summer-critical sub-transmission system. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the system s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 92 Forecast maximum demand against the ERTS-MGE-LD-ERTS system ratings ERTS-MGE-LD-ERTS Year Actual Load Forecast Load Summer (N-1) rating Summer (N) rating During summer , the maximum demand on the ERTS-MGE-LD-ERTS sub-transmission system exceeded its (N-1) rating. Given a steady demand growth over the next five years, a significant amount of energy would be at risk in the event of a forced 66 kv line outage during maximum demand periods. The figure below depicts the expected energy at risk with either the ERTS-MGE 66 kv line or ERTS-LD 66 kv line out-of-service for the 10% PoE maximum demand forecast, and the hours per year that the 10% PoE maximum demand is forecast is expected to exceed the (N-1) system rating. The graph also shows the value to customers of the expected unserved energy in each year, for the 10% PoE maximum demand forecast. Review by: 12/2014 Page 198 of 309

200 Expected Energy at Risk above N-1 (kwh) and Hours at Risk above N-1 (hrs) Customer value of lost load ($) Strategy Figure 93 Annual energy, hours at risk and expected customer value of lost load Magnitude of load at risk above (N-1) and value of lost load at ERTS- MGE-LD-ERTS 1200 $70, $60, $50,000 $40,000 $30,000 $20, $10, Year $0 Hours at risk above N-1 (hours) Expected energy above N-1 (kwhr) Customer value of lost load ($) As shown above, if there is an outage of a sub-transmission line from ERTS during summer maximum demand periods, there will be insufficient capacity in the sub-transmission system to supply all demand in for about 48 hours. It is emphasised however that the probability of a major outage of one of the sub-transmission lines occurring over the duration of high load is very low. When the energy at risk is weighted by this low probability, the expected energy at risk is estimated to be 338 kwh in summer If no action is taken, this figure is expected to rise to 1,017 kwh in summer , with a value to customers of around $64.1k. 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. Implement a contingency plan to transfer load to adjacent sub-transmission systems and the use of dynamic line ratings. UE has established and implemented the necessary plans that enable load transfers under contingency conditions, via the distribution network. These plans are reviewed annually prior to the summer season. Transfer capability away from this sub-transmission system is assessed at 40.9 MVA for summer Upgrade the ERTS-MGE and ERTS-LD 66 kv circuits. These lines were upgraded to the standard 66 kv overhead conductor in Therefore, any further capacity upgrade would require larger non-standard conductors and augmentation of line circuit breakers to suit the higher rating. 3. Establish approximately 3.5 km 66 kv circuit from ERTS to connect to the MGE-LD 66 kv circuit. Review by: 12/2014 Page 199 of 309

201 4. Establish a new 66/22 kv zone substation with a separate sub-transmission system to offload the ERTS-MGE-LD-ERTS system. There are no vacant zone substation sites in the area and the cost of acquiring a new site would very likely make such an option uneconomic when lower-cost alternatives are available. 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. This could also facilitate the growth and emerging limitations in SPI Electricity s areas of Knoxfield and Rowville. Preferred network option(s) for alleviation of limitations UE proposes to maintain its existing contingency plans that include dynamic ratings and load transfers to adjacent sub-transmission systems for an unplanned outage of ERTS-MGE or ERTS- LD 66 kv lines under critical loading conditions until a long term solution is implemented. Therefore, no major demand related augmentation is planned for this sub-transmission system over the next five years. System summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. ERTS-MGE-LD-ERTS system Summer cyclic N Rating (MVA) Summer cyclic N-1 Rating (MVA) Embedded generation capacity (MW) 0.0 ERTS-MGE-LD-ERTS system % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 40.9 N-1 energy at risk at 10% PoE demand (MWh) 1,021 1,517 2,010 2,620 3,069 N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) ,017 Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 200 of 309

202 HTS sub-transmission systems There are currently three UE 66 kv sub-transmission systems connected to Heatherton Terminal Station (HTS) that supply nine UE zone substations. The three systems are: 1. HTS-M/MC-BR-HTS. 2. HTS-MR-BT-NB-HTS. 3. HTS-SR-CM-HT-HTS. HTS-M/MC-BR-HTS The HTS-M/MC-BR-HTS sub-transmission system supplies Mentone (M), Mordialloc (MC) and Beaumaris (BR) zone substations as shown below. Figure 94 - HTS-M/MC-BR-HTS sub-transmission system HTS BR MC M The critical limitation on this sub-transmission system is currently the HTS-BR 66 kv line for an outage of the HTS-M/MC 66 kv line. The operational cyclic (N) rating (all plant in-service) and the (N-1) rating of the system were reduced in 2013 due to significant increase in the maximum demand at MC zone substation. UE plans to commission the new Keysborough (KBH) zone substation by December 2014, which will be incorporated into this sub-transmission system. As part of this project, a second HTS-M 66 kv line will be established, using the presently out-of-service HTS-CRM No.1 66 kv line and Review by: 12/2014 Page 201 of 309

203 replace the existing 66 kv droppers at BR zone substation, to reinforce the system. Once commissioned, UE plans to offload parts of Dandenong South (DSH), Mordialloc (MC) and Noble Park (NP) zone substations onto the new KBH zone substation. The critical limitation on the new sub-transmission system at the completion of the KBH zone substation will be the HTS-M No.2 66 kv line for an outage of the HTS-M No.1 66 kv line. The planned new sub-transmission system is shown below. Figure 95 HTS-KBH-M/MC-BR-HTS sub-transmission system HTS KBH BR MC M Magnitude, probability and impact of loss of load HTS-M/MC-BR-HTS is a summer-critical sub-transmission system. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the system s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Review by: 12/2014 Page 202 of 309

204 Load (A) Strategy Figure 96 Forecast maximum demand against the HTS-M/MC-BR-HTS system ratings HTS-M/MC-BR-HTS Year Actual Load Forecast Load Summer (N-1) rating Summer (N) rating The demand for the HTS-M/MC-BR-HTS sub-transmission system is expected to exceed its (N-1) rating from summer The figure below depicts the expected energy at risk with the HTS-M/MC 66 kv line is out-ofservice (until December 2014) and the HTS-M No.1 66 kv line out-of-service (from December 2014), for the 10% PoE maximum demand forecast, and the hours per year that the 10% PoE maximum demand is forecast is expected to exceed the (N-1) sub-transmission system rating. The graph also shows the value to customers of the expected unserved energy in each year, for the 10% PoE maximum demand forecast. Review by: 12/2014 Page 203 of 309

205 Expected Energy at Risk above N-1 (kwh) and Hours at Risk above N-1 (hrs) Customer value of lost load ($) Strategy Figure 97 Annual energy, hours at risk and expected customer value of lost load Magnitude of load at risk above (N-1) and value of lost load at HTS- M/MC-BR-HTS 500 $30, $25, Year $20,000 $15,000 $10,000 $5,000 $0 Hours at risk above N-1 (hours) Expected energy above N-1 (kwhr) Customer value of lost load ($) As shown above, if there is a forced outage of the HTS-M/MC 66 kv line during summer maximum demand periods, there will be insufficient capacity in the sub-transmission system to supply all demand in for about 42 hours. It is emphasised however that the probability of a major outage of one of the sub-transmission lines occurring over the duration of high load is very low. When the energy at risk is weighted by this low probability, the expected energy at risk is estimated to be 446 kwh in summer With the reinforcement of this system in December 2014, this figure is expected to fall to 177 kwh in summer , with a value to customers of around $11.2k. 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. Implement a contingency plan to transfer load to adjacent sub-transmission systems and the use of dynamic line ratings. UE has established and implemented the necessary plans that enable load transfers under contingency conditions, via the distribution network. These plans are reviewed annually prior to the summer season. Transfer capability away from this sub-transmission system is assessed at 24.2 MVA for summer Upgrade HTS-M No.2 66 kv circuit. Review by: 12/2014 Page 204 of 309

206 Preferred network option(s) for alleviation of limitations UE proposes to maintain its existing contingency plans that include dynamic ratings and load transfers to adjacent sub-transmission systems in the event of an emergency. Therefore, no major demand related augmentation is planned for this sub-transmission system over the next five years. System summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. HTS-M/MC-BR-HTS system Summer cyclic N Rating (MVA) Summer cyclic N-1 Rating (MVA) Embedded generation capacity (MW) 0.0 HTS-M/MC-BR-HTS system % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 24.2 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 205 of 309

207 Load (A) 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 circuits of the system, HTS-MR and HTS-NB 66 kv lines, were reconductored to achieve a summer cyclic rating of 1120 Amps. However, the operational cyclic (N) rating (all plant in-service) and the (N-1) rating of the system is now limited by the two middle circuits of the system, BT-NB and BT-MR 66 kv lines. 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. Similarly, for an outage of the HTS-MR 66 kv line, the BT-NB 66 kv line is constrained. Magnitude, probability and impact of loss of load HTS-MR-BT-NB-HTS is a summer-critical sub-transmission system. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the system s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 98 Forecast maximum demand against the HTS-MR-BT-NB-HTS system ratings HTS-MR-BT-NB-HTS Year Actual Load Forecast Load Summer (N-1) rating Summer (N) rating The demand on the HTS-MR-BT-NB-HTS sub-transmission system is expected to exceed its (N-1) rating from summer The figure below depicts the expected energy at risk with the HTS-NB 66 kv line out-of-service for the 10% PoE maximum demand forecast, and the hours per year that the 10% PoE maximum Review by: 12/2014 Page 206 of 309

208 Expected Energy at Risk above N-1 (kwh) and Hours at Risk above N-1 (hrs) Customer value of lost load ($) Strategy demand is forecast is expected to exceed the (N-1) system rating. The graph also shows the value to customers of the expected unserved energy in each year, for the 10% PoE maximum demand forecast. Figure 99 Annual energy, hours at risk and expected customer value of lost load Magnitude of load at risk above (N-1) and value of lost load at HTS- MR-BT-NB-HTS 60 $4, $3,500 $3, $2,500 $2, $1,500 $1, $ Year $0 Hours at risk above N-1 (hours) Expected energy above N-1 (kwhr) Customer value of lost load ($) As shown above, if there is a forced outage of the HTS-NB 66 kv line during summer maximum demand periods, there will be insufficient capacity in the sub-transmission system to supply all demand in for about 9 hours. It is emphasised however that the probability of a major outage of the sub-transmission line occurring over the duration of high load is very low. When the energy at risk is weighted by this low probability, the expected energy at risk is estimated to be 19 kwh in summer If no action is taken, this figure is expected to rise to 56 kwh in summer , with a value to customers of around $3.6k. 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. Implement a contingency plan to transfer load to adjacent sub-transmission systems and the use of dynamic line ratings. UE has established and implemented the necessary plans that enable load transfers under contingency conditions, via the distribution network. These plans are reviewed annually prior to the summer season. Transfer capability away from this sub-transmission system is assessed at 16.2 MVA for summer Thermally uprate approximately 1.3 km of the BT-MR 66 kv line at an approximate cost of $200k. Review by: 12/2014 Page 207 of 309

209 3. Thermally uprate approximately 2.9 km of the BT-NB 66 kv line at an approximate cost of $300k. 4. Demand reduction, in the order of 2 MW or more, connected at BT, MR or NB supply areas in December 2014, can defer the need for augmentation in by 12 months. UE has developed a number of innovative network tariffs that encourage voluntary demand reduction during times of network limitation. The amount of demand reduction depends on the tariff uptake and will be taken into consideration when determining the optimum timing for the capacity augmentation. 5. Embedded generation, in the order of 2 MW or more, connected at BT, MR or NB supply areas in December 2014, can defer the need for augmentation by 12 months. Preferred network option(s) for alleviation of limitations UE proposes to maintain its existing contingency plans that include dynamic ratings and load transfers to adjacent sub-transmission systems in the event of an emergency. As a means of managing the emerging limitation and the diminishing transfer capability to adjacent sub-transmission systems, UE proposes to implement the following minor works by December 2014: 1. Thermally uprate approximately 1.3 km of the BT-MR 66 kv line at an approximate cost of $200k. 2. Thermally uprate approximately 2.9 km of the BT-NB 66 kv line at an approximate cost of $300k. Once commissioned, the system s rating would be adequate to meet the demand on the HTS-MR- BT-NB-HTS sub-transmission system beyond this planning period. This plan will be undertaken in the absence of any commitment by interested parties to offer network support services by installing local generation or through demand side management initiatives that would reduce address the limitations on this sub-transmission system. The estimated total annual cost of the preferred network option is $50,000. This cost provides a broad upper bound indication of the maximum contribution from UE which may be available to non-network service providers to reduce forecast demand and defer or avoid this augmentation. UE invites non-network service providers to submit their proposals to alleviate limitations on the HTS-MR-BT-NB-HTS sub-transmission system. Review by: 12/2014 Page 208 of 309

210 System summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. HTS-MR-BT-NB-HTS system Summer cyclic N Rating (MVA) Summer cyclic N-1 Rating (MVA) Embedded generation capacity (MW) 0.0 HTS-MR-BT-NB-HTS system % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 16.2 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 209 of 309

211 Load (A) Strategy HTS-SR-CM-HT-HTS The HTS-SR-CM-HT-HTS 66kV sub-transmission system supplies Sandringham (SR), Cheltenham (CM) and Heatherton (HT) 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. Magnitude, probability and impact of loss of load HTS-SR-CM-HT-HTS is a summer-critical sub-transmission system. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the system s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 100 Forecast maximum demand against the HTS-SR-CM-HT-HTS system ratings HTS-SR-CM-HT-HTS Year Actual Load Forecast Load Summer (N-1) rating Summer (N) rating The demand for the HTS-SR-CM-HT-HTS sub-transmission system is expected to remain within its (N-1) rating for the next five years. Therefore, no major demand related augmentation is planned for this system over the next five years. Review by: 12/2014 Page 210 of 309

212 System summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. HTS-SR-CM-HT-HTS system Summer cyclic N Rating (MVA) Summer cyclic N-1 Rating (MVA) Embedded generation capacity (MW) 0.0 HTS-SR-CM-HT-HTS system % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 12.6 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 211 of 309

213 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-OR-OAK-MTS. There are currently six UE 22 kv radial feeders exiting MTS. These feeders supply Surrey Hills (SH) and Burwood (BH) 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 101 MTS-CFD-EL-EM-MTS sub-transmission system MTS CFD EL EM 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. Review by: 12/2014 Page 212 of 309

214 Load (A) 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. Magnitude, probability and impact of loss of load MTS-CFD-EL-EM-MTS is a summer-critical sub-transmission system. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the system s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 102 Forecast maximum demand against the MTS-CFD-EL-EM-MTS system ratings MTS-CFD-EL-EM-MTS Year Actual Load Forecast Load Summer (N-1) rating Summer (N) rating The demand for the MTS-CFD-EL-EM-MTS sub-transmission system is expected to remain within its (N-1) rating for the next five years. Therefore, no major demand related augmentation is planned for this system over the next five years. Review by: 12/2014 Page 213 of 309

215 System summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. MTS-CFD-EL-EM-MTS system Summer cyclic N Rating (MVA) Summer cyclic N-1 Rating (MVA) Embedded generation capacity (MW) 0.0 MTS-CFD-EL-EM-MTS system % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 14.2 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 214 of 309

216 Load (A) Strategy MTS-OR-OAK-MTS The MTS-OR-OAK-MTS 66kV sub-transmission system supplies Ormond (OR) and Oakleigh (OAK) 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. Magnitude, probability and impact of loss of load MTS-OR-OAK-MTS is a summer-critical sub-transmission system. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the system s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 103 Forecast maximum demand against the MTS-OR-OAK-MTS system ratings MTS-OR-OAK-MTS Year Actual Load Forecast Load Summer (N-1) rating Summer (N) rating The demand on the MTS-OR-OAK-MTS sub-transmission system is expected to marginally exceed its (N-1) rating from summer As a means of managing the emerging limitation, UE intends to assess a minor augmentation involving reconductoring of approximately 100 metres of the MTS-OR 66 kv line by December If it proceeds, this augmentation would increase the system s (N-1) rating from 715 Amps to 830 Amps. Therefore, no major demand related augmentation is planned for this system within this planning period. Review by: 12/2014 Page 215 of 309

217 System summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. MTS-OR-OAK-MTS system Summer cyclic N Rating (MVA) Summer cyclic N-1 Rating (MVA) 81.7 Embedded generation capacity (MW) 0.0 MTS-OR-OAK-MTS system % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 16.8 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 216 of 309

218 Load (A) 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. The load on this system has been declining over the last few years partly due to gradual conversion of the 6.6 kv distribution network to 22 kv. 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. SH is a very old substation and UE reviewed the condition of the entire SH network in Based on the review, UE is in the process of replacing 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. Magnitude, probability and impact of loss of load MTS-SH-MTS is a summer-critical sub-transmission system. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the system s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 104 Forecast maximum demand against the MTS-SH-MTS system ratings MTS-SH-MTS Year Actual Load Forecast Load Summer (N-1) rating Summer (N) rating The demand on the MTS-SH-MTS sub-transmission system is expected to remain within its (N-1) rating for the next five years. Therefore, no major demand related augmentation is planned for this system over the next five years. Review by: 12/2014 Page 217 of 309

219 System summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. MTS-SH-MTS system Summer cyclic N Rating (MVA) 22.4 Summer cyclic N-1 Rating (MVA) 14.3 Embedded generation capacity (MW) 0.0 MTS-SH-MTS system % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 0 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 218 of 309

220 Load (A) 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. Magnitude, probability and impact of loss of load MTS-BW-MTS is a summer-critical sub-transmission system. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the system s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 105 Forecast maximum demand against the MTS-BW-MTS system ratings MTS-BW-MTS Year Actual Load Forecast Load Summer (N-1) rating Summer (N) rating The demand on the MTS-BW-MTS sub-transmission system is expected to remain within its (N-1) rating for the next five years. Therefore, no major demand related augmentation is planned for this system over the next five years. Review by: 12/2014 Page 219 of 309

221 System summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. MTS-BW-MTS system Summer cyclic N Rating (MVA) 36.2 Summer cyclic N-1 Rating (MVA) 25.3 Embedded generation capacity (MW) 0.0 MTS-BW-MTS system % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 7.3 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 220 of 309

222 RTS sub-transmission systems There are two shared 66 kv sub-transmission systems associated with UE demand connected to Richmond Terminal Station (RTS). These two systems are: 1. RTS-EW-SK-RTS. 2. RTS-K-CL-RTS. RTS-EW-SK-RTS The RTS-EW-SK-RTS 66kV 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. The ownership of the 66 kv assets supplying EW and SK zone substations are listed in the table below. Table 17 Network ownership arrangement 66kV Line RTS-EW RTS-SK EW-SK Ownership Distribution asset owned by UE Distribution asset owned by CitiPower Distribution asset owned by UE Embedded generation in the area helps to reduce demand at SK zone substation by approximately 5.7 MW. The critical limitation on this sub-transmission system is currently the RTS-SK 66 kv line for an outage of the RTS-EW 66 kv line. Similarly, for an outage of the RTS-SK 66 kv line, the RTS-EW 66 kv line is constrained. Magnitude, probability and impact of loss of load RTS-EW-SK-RTS is a summer-critical sub-transmission system. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the system s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Review by: 12/2014 Page 221 of 309

223 Load (A) Strategy Figure 106 Forecast maximum demand against the RTS-EW-SK-MTS system ratings RTS-EW-SK-RTS Year Actual Load with Generation Forecast Load with Generation Summer (N-1) rating Summer (N) rating Actual Load without Generation Forecast Load without Generation With the embedded generation, the demand on the RTS-EW-SK-RTS sub-transmission system is expected to exceed its (N-1) rating from summer The figure below depicts the expected energy at risk with the RTS-EW 66 kv line out-of-service for the 10% PoE maximum demand forecast, and the hours per year that the 10% PoE maximum demand is forecast is expected to exceed the (N-1) system rating. The graph also shows the value to customers of the expected unserved energy in each year, for the 10% PoE maximum demand forecast. Review by: 12/2014 Page 222 of 309

224 Expected Energy at Risk above N-1 (kwh) and Hours at Risk above N-1 (hrs) Customer value of lost load ($) Strategy Figure 107 Annual energy, hours at risk and expected customer value of lost load Magnitude of load at risk above (N-1) and value of lost load at RTS- EW-SK-RTS with Generation 7 $400 6 $ $300 $250 $200 $150 $100 $ Year $0 Hours at risk above N-1 (hours) Expected energy above N-1 (kwhr) Customer value of lost load ($) As shown above, if there is a forced outage of the RTS-EW 66 kv line, there will be insufficient capacity on the sub-transmission system to supply all demand in summer for about 1 hour. It is emphasised however that the probability of a major outage of one of the subtransmission lines occurring over the duration of high load is very low. When the energy at risk is weighted by this low probability, the expected energy at risk is estimated to be 1 kwh in summer If no action is taken, this figure is expected to rise to 6 kwh in summer , with a value to customers of around $0.4k. In the absence of the embedded generation, the expected energy at risk is estimated to be to be 27 kwh in summer If no action is taken, this figure is expected to rise to 122 kwh in summer , with a value to customers of around $7.6k. 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. Implement a contingency plan to transfer load to adjacent sub-transmission systems and the use of dynamic line ratings. UE and CitiPower have established and implemented the necessary plans that enable load transfers under contingency conditions, via the distribution network. These plans are reviewed annually prior to the summer season. Transfer capability away from EW and SK zone substation is assessed at 5.4 MVA and 5 MVA respectively for summer Upgrade the RTS-SK 66 kv circuit by replacing the droppers at SK zone substation. Review by: 12/2014 Page 223 of 309

225 3. Upgrade the RTS-EW 66 kv circuit by replacing the droppers at EW zone substation. 4. Demand reduction, in the order of 2 MW or more, connected at EW and/or SK supply areas in December 2015, can defer the need for augmentation by 12 months. UE has developed a number of innovative network tariffs that encourage voluntary demand reduction during times of network limitation. The amount of demand reduction depends on the tariff uptake and will be taken into consideration when determining the optimum timing for the capacity augmentation. 5. Embedded generation, in the order of 2 MW or more, connected at EW and/or SK supply areas in December 2015, can defer the need for augmentation by 12 months. Preferred network option(s) for alleviation of limitations CitiPower proposes to maintain its existing contingency plans that include dynamic ratings and transfer load from SK zone substation to adjacent sub-transmission systems in the event of an emergency. UE also plans to implement similar transfers away from EW zone substation. As a means of managing the emerging limitation and the diminishing transfer capability to adjacent sub-transmission systems, UE proposes to assess an upgrade of the droppers on the RTS-EW 66 kv line at EW zone substation by December 2015, at an approximate cost of $75k. This augmentation would increase the system s (N-1) rating from 750 Amps to 830 Amps. This plan would be undertaken in the absence of any commitment by interested parties to offer network support services by installing local generation or through demand side management initiatives that would reduce address the limitations on this sub-transmission system. The estimated total annual cost of the preferred network option is $7,500. This cost provides a broad upper bound indication of the maximum contribution from the distributors which may be available to non-network service providers to reduce forecast demand and defer or avoid this augmentation. UE invites non-network service providers to submit their proposals to alleviate limitations on the RTS-EW-SK-RTS sub-transmission system. Review by: 12/2014 Page 224 of 309

226 System summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. RTS-EW-SK-RTS system Summer cyclic N Rating (MVA) Summer cyclic N-1 Rating (MVA) 85.7 Embedded generation capacity (MW) 5.7 RTS-EW-SK-RTS system (With generation) % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 10.4 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) RTS-EW-SK-RTS system (Without generation) % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 11.4 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 225 of 309

227 RTS-K-CL-RTS The RTS-K-CL-RTS 66kV 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. Table 18 Network ownership arrangement 66kV Line RTS-K RTS-CL CL-K Ownership Distribution asset owned by UE Distribution asset owned by CitiPower Distribution asset owned by CitiPower 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. The station assets that are limiting the rating of the RTS-K 66 kv line will be upgraded as part of the RTS redevelopment project undertaken by SPI PowerNet. This upgrade is expected to be commissioned by December Magnitude, probability and impact of loss of load RTS-K-CL-RTS is a summer-critical sub-transmission system. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the system s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Review by: 12/2014 Page 226 of 309

228 Load (A) Strategy Figure Forecast maximum demand against the RTS-K-CL-RTS system ratings RTS-K-CL-RTS Year Actual Load Forecast Load Summer (N-1) rating Summer (N) rating The demand on the RTS-K-CL-RTS sub-transmission system has been above its (N-1) rating since summer The figure below depicts the expected energy at risk 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 is forecast is expected to exceed the (N-1) system rating. The graph also shows the value to customers of the expected unserved energy in each year, for the 10% PoE maximum demand forecast. Review by: 12/2014 Page 227 of 309

229 Expected Energy at Risk above N-1 (kwh) and Hours at Risk above N-1 (hrs) Customer value of lost load ($) Strategy Figure 109 Annual energy, hours at risk and expected customer value of lost load Magnitude of load at risk above (N-1) and value of lost load at RTS-K- CL-RTS 140 $9, $8, Year $7,000 $6,000 $5,000 $4,000 $3,000 $2,000 $1,000 $0 Hours at risk above N-1 (hours) Expected energy above N-1 (kwhr) Customer value of lost load ($) As shown above, if there is an outage of the RTS-CL 66 kv line, there will be insufficient capacity on the sub-transmission system to supply all demand in summer for about 43 hours. It is emphasised however that the probability of a major outage of one of the sub-transmission lines occurring over the duration of high load is very low. When the energy at risk is weighted by this low probability, the expected energy at risk is estimated to be 76 kwh in summer If no action is taken, this figure is expected to rise to 123 kwh in summer , with a value to customers of around $7.8k. 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. Implement a contingency plan to transfer load to adjacent sub-transmission systems and the use of dynamic line ratings. UE has established and implemented the necessary plans that enable load transfers under contingency conditions, via the distribution network. These plans are reviewed annually prior to the summer season. Transfer capability away from K and CL is assessed at 16.8 MVA for summer Upgrade the RTS-K 66 kv line. This line has already been previously upgraded by increasing the conductor maximum operating temperature to 82ºC. The line will be further upgraded in around 2016 as a result of the Richmond Terminal Station redevelopment project. 3. Transfer K to a new sub-transmission system supplied from Malvern Terminal Station (MTS) by establishing new 66 kv lines. The new 66 kv lines would need to be added to Review by: 12/2014 Page 228 of 309

230 the existing ROTS-RTS 220 kv tower line over a distance of 4.4 km. Although this option is expensive, it may provide additional benefit by reducing demand on the transmission connection assets at RTS. Preferred network option(s) for alleviation of limitations UE proposes to maintain its existing contingency plans that include dynamic ratings and transfer load from K zone substation to adjacent sub-transmission systems in the event of an emergency. CitiPower also plans to implement similar transfers away from CL zone substation. Therefore, no major demand related augmentation is planned for this system over the next five years. System summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. RTS-K-CL-RTS system Summer cyclic N Rating (MVA) Summer cyclic N-1 Rating (MVA) 93.2 Embedded generation capacity (MW) 0.0 RTS-K-CL-RTS system % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 16.8 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 229 of 309

231 Load (A) Strategy 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 SPIE also own a number of distribution feeders from RWTS at 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 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. Magnitude, probability and impact of loss of load RWTS-BH-NW-RWTS is a summer-critical sub-transmission system. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the system s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 110 Forecast maximum demand against the RWTS-BH-NW-RWTS system ratings RWTS-BH-NW-RWTS Year Actual Load Forecast Load Summer (N-1) rating Summer (N) rating Review by: 12/2014 Page 230 of 309

232 The demand on the RWTS-BH-NW-RWTS sub-transmission system is expected to marginally exceed its (N-1) rating from summer However, the expected energy at risk is insignificant over the planning period. Therefore, no major demand related augmentation is planned for this system over the next five years. System summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. RWTS-BH-NW-RWTS system Summer cyclic N Rating (MVA) Summer cyclic N-1 Rating (MVA) Embedded generation capacity (MW) 0.0 RWTS-BH-NW-RWTS system % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 28.1 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 231 of 309

233 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-OE-CDA-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. Table 19 Network ownership arrangement 66kV Line SVTS-EB SVTS-RD EB-RD Ownership Distribution asset owned by UE Distribution asset owned by CitiPower Distribution asset owned by UE The critical limitation on the sub-transmission system is currently the SVTS-RD 66 kv line for an outage of the SVTS-EB 66 kv line. Similarly, for an outage of the SVTS-RD 66 kv line, the SVTS- EB 66 kv line is constrained. The 2012 DSPR proposed that RD zone substation can be transferred away from SVTS to MTS by creating a new MTS-RD-BW-MTS sub-transmission system. This option relied on converting UE owned and operated Burwood (BW) zone substation from 22 kv to 66 kv and constructing two new 66 kv lines. In 2013, UE and CitiPower jointly undertook cost-benefit assessment of this option. Given the cost of converting BW zone substation was significantly higher than originally anticipated, the joint assessment concluded that under the present maximum demand growth projections, there are other cost-effective solutions that can be implemented to provide a solution to the limitations on this sub-transmission system. Review by: 12/2014 Page 232 of 309

234 Load (A) Strategy Magnitude, probability and impact of loss of load SVTS-EB-RD-SVTS is a summer-critical sub-transmission system. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the system s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 111 Forecast maximum demand against the SVTS-EB-RD-SVTS system ratings SVTS-EB-RD-SVTS Year Actual Load Forecast Load Summer (N-1) rating Summer (N) rating The demand on the SVTS-EB-RD-SVTS sub-transmission system has been above its (N-1) rating since summer The figure below depicts the expected energy at risk with the SVTS-EB 66 kv line out-of-service for the 10% PoE maximum demand forecast, and the hours per year that the 10% PoE maximum demand is forecast is expected to exceed the (N-1) system rating. The graph also shows the value to customers of the expected unserved energy in each year, for the 10% PoE maximum demand forecast. Review by: 12/2014 Page 233 of 309

235 Expected Energy at Risk above N-1 (kwh) and Hours at Risk above N-1 (hrs) Customer value of lost load ($) Strategy Figure 112 Annual energy, hours at risk and expected customer value of lost load Magnitude of load at risk above (N-1) and value of lost load at SVTS- EB-RD-SVTS 4500 $300, $250, Year $200,000 $150,000 $100,000 $50,000 $0 Hours at risk above N-1 (hours) Expected energy above N-1 (kwhr) Customer value of lost load ($) As shown above, if there is a forced sub-transmission line outage of the SVTS-EB 66 kv line, there will be insufficient capacity on the remaining line to supply all demand in summer for about 82 hours. It is emphasised however that the probability of a major outage of one of the subtransmission lines occurring over the duration of high load is very low. When the energy at risk is weighted by this low probability, the expected energy at risk is estimated to be 1,759 kwh in summer If no action is taken, this figure is expected to rise to 4,105 kwh in summer , with a value to customers of around $259k. 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. Implement a contingency plan to transfer load to adjacent sub-transmission systems and the use of dynamic line ratings. UE has established and implemented the necessary plans that enable load transfers under contingency conditions, via the distribution network. These plans are reviewed annually prior to the summer season. Transfer capability away from EB and RD is assessed at 20.1 MVA for summer Re-conductor the SVTS-RD 66 kv line, at an estimated cost of $7 million. 3. Re-conductor the SVTS-EB line, over a distance of 750 metres, at an estimated cost of $750k. 4. Transfer RD from SVTS to Malvern Terminal Station (MTS) by creating a new subtransmission system MTS-RD-BW-MTS. As previously discussed, UE and CitiPower jointly Review by: 12/2014 Page 234 of 309

236 concluded that under the present maximum demand outlook, there are other cost-effective solutions that can be implemented to provide a solution to this sub-transmission system constraint. 5. Demand reduction, in the order of 2 MW or more, connected at EB and/or RD supply areas in December 2015, can defer the need for augmentation by 12 months. UE has developed a number of innovative network tariffs that encourage voluntary demand reduction during times of network limitation. The amount of demand reduction depends on the tariff uptake and will be taken into consideration when determining the optimum timing for the capacity augmentation. 6. Embedded generation, in the order of 2 MW or more, connected at EB and/or RD supply areas in December 2015, can defer the need for augmentation by 12 months. Preferred network option(s) for alleviation of limitations CitiPower proposes to implement contingency plans to transfer load quickly to adjacent subtransmission system for an unplanned outage of the SVTS-EB 66 kv line under critical loading conditions. In addition, 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. UE will also implement similar transfers away from EB until a long term solution is implemented. CitiPower proposes to upgrade the SVTS-RD 66 kv line in Upon completion, UE plans to consider reconductoring 750 metres of under-rated section on the SVTS-EB 66 kv line in This plan would be undertaken in the absence of any commitment by interested parties to offer network support services through demand side management initiatives that would reduce load on this sub-transmission system. The estimated total annual cost of the preferred network option is $775,000. This cost provides a broad upper bound indication of the maximum contribution from the distributors which may be available to non-network service providers to reduce forecast demand and defer or avoid this augmentation. UE and CitiPower invite non-network service providers to submit their proposals to alleviate limitations on the SVTS-EB-RD-SVTS sub-transmission system. The preferred solution will be subject to a joint RIT-D led by CitiPower after which a final decision will be made. Review by: 12/2014 Page 235 of 309

237 System summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. SVTS-EB-RD-SVTS system Summer cyclic N Rating (MVA) Summer cyclic N-1 Rating (MVA) 80.0 Embedded generation capacity (MW) 0.0 SVTS-EB-RD-SVTS system % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 20.1 N-1 energy at risk at 10% PoE demand (MWh) 1,909 2,386 2,978 3,549 4,453 N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) 1,759 2,200 2,745 3,271 4,105 Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 236 of 309

238 Load (A) 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. Magnitude, probability and impact of loss of load SVTS-GW-NO-SVTS is a summer-critical sub-transmission system. The figure below depicts the 10% PoE weather-corrected actual demand, 10% PoE summer maximum demand forecast together with the system s operational cyclic (N) rating and the (N-1) rating. Figure 113 Forecast maximum demand against the SVTS-GW-NO-SVTS system ratings SVTS-GW-NO-SVTS Year Actual Load Forecast Load Summer (N-1) rating Summer (N) rating The demand on the SVTS-GW-NO-SVTS sub-transmission system is expected to remain within its (N-1) rating for the next five years. Therefore, no major demand related augmentation is planned for this system over the next five years. Review by: 12/2014 Page 237 of 309

239 System summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. SVTS-GW-NO-SVTS system Summer cyclic N Rating (MVA) Summer cyclic N-1 Rating (MVA) Embedded generation capacity (MW) 0.0 SVTS-GW-NO-SVTS system % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 21.3 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 238 of 309

240 Load (A) 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 by approximately 7 MW on weekdays between 7:00 am and 11:00 pm. UE does not currently have network support agreements with these generators. UE plans to commission the new Keysborough (KBH) zone substation by December Once commissioned, load will be transferred away from NP to the new KBH zone substation. The proposed transfer is expected to reduce the demand on this system. However, the demand on HTS-M/MC-BR-HTS is expected to increase from December The critical limitation on this sub-transmission system is currently the SVTS-NP 66 kv line for an outage of the SVTS-SS 66 kv line. Similarly, for an outage of the SVTS-NP 66 kv line, the SVTS- SS 66 kv line is constrained. Magnitude, probability and impact of loss of load SVTS-NP-SS-SVTS is a summer-critical sub-transmission system. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the system s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 114 Forecast maximum demand against the SVTS-NP-SS-SVTS system ratings SVTS-NP-SS-SVTS Year Actual Load with Generation Forecast Load with Generation Summer (N-1) rating Summer (N) rating Actual Load without Generation Forecast Load without Generation Review by: 12/2014 Page 239 of 309

241 With the exception of last two summers, the maximum demand on this sub-transmission system has exceeded its (N-1) rating. However, once the load is transferred from NP to KBH zone substation, the maximum demand on this system is expected to fall below its (N-1) rating with the generation in-service. In the absence of the generation, the forecast maximum demand is expected to marginally exceed the system s (N-1) rating from summer Therefore, no major demand related augmentation is planned at for this system over the next five years. Preferred network option(s) for alleviation of limitations Until KBH is commissioned, UE proposes to implement a contingency plan to transfer load to adjacent sub-transmission systems and the use of dynamic line ratings. UE is able to transfer about 41.9 MVA (for summer ), away from the system in the event of an emergency. System summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. SVTS-NP-SS-SVTS system Summer cyclic N Rating (MVA) Summer cyclic N-1 Rating (MVA) Embedded generation capacity (MW) 7.0 SVTS-NP-SS-SVTS system (With generation) % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 41.9 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 240 of 309

242 Load (A) Strategy SVTS-OE-CDA-SVTS The SVTS-OE-CDA-SVTS 66 kv sub-transmission system supplies Oakleigh East (OE) and Clarinda (CDA) zone substations in a looped arrangement. In 2012, the relocatable transformer 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. The critical section on this sub-transmission system is currently the SVTS-OE 66 kv line for an outage of the SVTS-CDA 66 kv line (or vice versa). Magnitude, probability and impact of loss of load SVTS-OE-CDA-SVTS is a summer-critical sub-transmission system. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the system s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 115 Forecast maximum demand against the SVTS-OE-CDA-SVTS system ratings SVTS-OE-CDA-SVTS Year Actual Load Forecast Load Summer (N-1) rating Summer (N) rating The demand on the SVTS-OE-CDA-SVTS sub-transmission system is expected to remain within its (N-1) rating for the next five years. Therefore, no major demand related augmentation is planned for this system over the next five years. Review by: 12/2014 Page 241 of 309

243 System summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. SVTS-OE-CDA-SVTS system Summer cyclic N Rating (MVA) Summer cyclic N-1 Rating (MVA) 65.2 Embedded generation capacity (MW) 0.0 SVTS-OE-CDA-SVTS system % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 31.0 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 242 of 309

244 Load (A) 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. 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. Similarly, for an outage of the SVTS-SV 66 kv line, the SVTS-SVW 66 kv line is constrained. Magnitude, probability and impact of loss of load SVTS-SV-SVW-SVTS is a summer-critical sub-transmission system. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the system s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 116 Forecast maximum demand against the SVTS-SV-SVW-SVTS system ratings SVTS-SV-SVW-SVTS Year Actual Load Forecast Load Summer (N-1) rating Summer (N) rating The demand on the SVTS-SV-SVW-SVTS sub-transmission system is expected to exceed its (N- 1) rating from summer However, the expected energy at risk is insignificant over the planning period. Therefore, no major demand related augmentation is planned for this system over the next five years. Review by: 12/2014 Page 243 of 309

245 System summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. SVTS-SV-SVW-SVTS system Summer cyclic N Rating (MVA) Summer cyclic N-1 Rating (MVA) Embedded generation capacity (MW) 0.0 SVTS-SV-SVW-SVTS system % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 20.4 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 244 of 309

246 TBTS sub-transmission systems At the time of writing this report, there are currently three 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-FSH-MTN-TBTS. 3. TBTS-DMA-TBTS. Rosebud (RBD) and Sorrento (STO) zone substations are connected to DMA through a ring bus and are presently supplied through the TBTS-DMA-TBTS system. In order to optimise the sub-transmission capacity utilisation in the Mornington Peninsula, UE is currently connecting the TBTS-FSH-MTN-TBTS and the TBTS-DMA-TBTS systems together. This project is expected to be commissioned by early 2014 subject to completion of changes to the load shedding arrangements at TBTS. Therefore, the combined meshed system will be considered as a single sub-transmission system. TBTS-HGS-TBTS The TBTS-HGS-TBTS 66kV sub-transmission system supplies the Hastings (HGS) zone substation in a looped arrangement. Magnitude, probability and impact of loss of load TBTS-HGS-TBTS is a summer-critical sub-transmission system. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the system s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Review by: 12/2014 Page 245 of 309

247 Load (A) Strategy Figure 117 Forecast maximum demand against the TBTS-HGS-TBTS system ratings TBTS-HGS-TBTS Year Actual Load Forecast Load Summer (N-1) rating Summer (N) rating The demand on the TBTS-HGS-TBTS sub-transmission system is expected to remain within its (N-1) rating for the next five years. Therefore, no major demand related augmentation is planned for this system over the next five years. Review by: 12/2014 Page 246 of 309

248 System summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. TBTS-HGS-TBTS system Summer cyclic N Rating (MVA) Summer cyclic N-1 Rating (MVA) 91.5 Embedded generation capacity (MW) 0.0 TBTS-HGS-TBTS system % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 20.0 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 247 of 309

249 TBTS-FSH-MTN-DMA-TBTS The existing TBTS-FSH-MTN-TBTS and the TBTS-DMA-TBTS sub-transmission systems are planned to be connected together to form the new TBTS-FSH-MTN-DMA-TBTS sub-transmission system in early Even though this development will improve the utilisation of subtransmission assets in the Mornington Peninsula, it does not fully alleviate the capacity and voltage limitations in the network. Rosebud (RBD) and Sorrento (STO) zone substations are connected to DMA as a secondary system and are presently supplied through the TBTS-DMA-TBTS system as shown below. Figure TBTS-FSH-MTN-DMA-TBTS sub-transmission system TBTS FSH MTN DMA RBD STO Review by: 12/2014 Page 248 of 309

250 Load (A) Strategy UE has identified a risk of voltage collapse in the lower part of the Mornington Peninsula in the event of an outage of either of the incoming sub-transmission lines to DMA during maximum demand periods. Given the relatively long sub-transmission lines extending to STO from TBTS, the voltage constraint is expected to be prominent over the thermal capacity of the system. UE installed capacitor banks at STO to improve voltage regulation in the lower part of the Mornington Peninsula. As a result, the risk of loss of supply due to excessive voltage drop under single contingency conditions during maximum demand periods has been reduced. Given the multiple 66 kv supply routes 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. Magnitude, probability and impact of loss of load TBTS-FSH-MTN-DMA-TBTS is a summer-critical sub-transmission system operating at 66kV. The figure below depicts the 10% PoE summer maximum demand forecast together with the system s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 119 Forecast maximum demand against the TBTS-FSH-MTN-DMA-TBTS system ratings TBTS-MTN-FSH-DMA-TBTS Year Forecast Load Summer (N-1) rating Summer (N) rating The demand on the TBTS-FSH-MTN-DMA-TBTS sub-transmission system is expected to exceed its (N-1) rating from summer The voltage constraint in the lower parts of the Mornington Peninsula is not eliminated as a result of linking the TBTS-FSH-MTN-TBTS and TBTS-DMA-TBTS sub-transmission systems together. Therefore, it is expected that the risk associated with both thermal and voltage constraints will continue to grow over the next five years. Review by: 12/2014 Page 249 of 309

251 Expected Energy at Risk above N-1 (kwh) and Hours at Risk above N-1 (hrs) Customer value of lost load ($) Strategy The figure below depicts the expected energy at risk for the entire sub-transmission system due to thermal capacity limitation following the loss of critical sections of the TBTS-FSH-MTN-DMA-TBTS system for the 10% PoE demand forecast, and the hours per year that the 10% PoE demand is forecast is expected to exceed the (N-1) station rating. The graph also shows the value to customers of the expected unserved energy in each year, for the 10% PoE demand forecast. This high level assessment does not include the risks associated with a voltage collapse as it requires a much more detailed assessment to quantify them. As a result, the risk associated with the subtransmission system in the Mornington Peninsula is higher than the values presented in the chart below. Figure 120 Annual energy, hours at risk and expected customer value of lost load Magnitude of load at risk above (N-1) and value of lost load at TBTS- FSH-MTN-DMA-TBTS 9000 $600, $500, Year $400,000 $300,000 $200,000 $100,000 $- Hours at risk above N-1 (hours) Expected energy above N-1 (kwhr) Customer value of lost load ($) As shown above, if there is a forced outage of critical sections of this system, there will be insufficient capacity to supply all demand in summer for about 14 hours. It is emphasised however that the probability of a major outage of one of the sub-transmission lines occurring over the duration of high load is very low. When the energy at risk is weighted by this low probability, the expected energy at risk is estimated to be 4881 kwh in summer If no action is taken, this figure is expected to rise to 7935 kwh in summer , with a value to customers of around $500.6k. Review by: 12/2014 Page 250 of 309

252 Load (A) Strategy DMA-RBD-DMA The DMA-RBD-DMA 66kV sub-transmission system supplies the Rosebud (RBD) and Sorrento (STO) zone substations in a looped arrangement with RBD only. Magnitude, Probability and Impact of Loss of Load DMA-RBD-DMA is a summer-critical sub-transmission system. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the system s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 121 Forecast maximum demand against the DMA-RBD-DMA system ratings DMA-RBD-DMA Year Actual Load Forecast Load Summer (N-1) rating Summer (N) rating The demand on the DMA-RBD-DMA sub-transmission system has been operated above its (N-1) rating since summer The figure below depicts the expected energy at risk on the system following loss of one of the two 66 kv lines from DMA to RBD for the 10% PoE maximum demand forecast, and the hours per year that the 10% PoE maximum demand is forecast is expected to exceed the (N-1) sub-transmission system rating. The graph also shows the value to customers of the expected unserved energy in each year, for the 10% PoE maximum demand forecast. Review by: 12/2014 Page 251 of 309

253 Expected Energy at Risk above N-1 (kwh) and Hours at Risk above N-1 (hrs) Customer value of lost load ($) Strategy Figure 122 Annual energy, hours at risk and expected customer value of lost load Magnitude of load at risk above (N-1) and value of lost load at DMA- RBD-DMA 800 $60, $50, $40,000 $30, $20, $10, Year $0 Hours at risk above N-1 (hours) Expected energy above N-1 (kwhr) Customer value of lost load ($) As shown above, if there is a forced outage of any one of the incoming sub-transmission lines to RBD, there will be insufficient capacity to supply all demand in summer for about 10 hours. It is emphasised however that the probability of a major outage of one of the subtransmission lines occurring over the duration of high load is very low. When the energy at risk is weighted by this low probability, the expected energy at risk is estimated to be 385 kwh in summer If no action is taken, this figure is expected to rise to 755 kwh in summer , with a value to customers of around $47.7k. Review by: 12/2014 Page 252 of 309

254 Load (A) Strategy RBD-STO-RBD The RBD-STO-RBD 66kV sub-transmission system supplies the Sorrento (STO) zone substation via two radial lines. Magnitude, Probability and Impact of Loss of Load RBD-STO-RBD is a summer-critical sub-transmission system. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the system s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 123 Forecast maximum demand against the RBD-STO-RBD system ratings RBD-STO-RBD Year Actual Load Forecast Load Summer (N-1) rating Summer (N) rating The demand on the RBD-STO-RBD sub-transmission system is expected to remain within its (N-1) rating for the next five years. Therefore, no major demand related augmentation is planned for this system over the next five years. Review by: 12/2014 Page 253 of 309

255 There are a number of other issues that require consideration that cannot be easily quantified by the value of expected load-at-risk presented above. These issues are specific to the subtransmission network in the Mornington Peninsula due to its unique geography as described below: Given the geographical area of the Mornington Peninsula which has vast areas of natural bush, parklands, open fields and other vegetation combined with some areas of high population density there exists a high risk of dangerous bushfire in many parts. With the existing sub-transmission lines running through high bushfire risk areas, there is a chance that a fire could cause one or both sub-transmission lines to trip either from direct radiant heat and poles burning or from smoke and ash causing insulation failure. In addition the DSE and/or CFA may intervene and request line isolation where live overhead lines represent a hazard to fire fighters battling fires adjacent to sub-transmission lines. Any resulting supply interruption could be prolonged particularly if significant asset damage is sustained or access for inspection and repair is hampered. The majority of the lower Mornington Peninsula electricity supply is fed by only two 66kV lines. Under single contingency conditions, the remaining line will need to support all three zone substations STO, RBD and DMA. Therefore there is a high risk of total loss of supply to the majority of the western section of the Mornington Peninsula in the event of a voltage collapse. Unlike other parts of the UE network where load can be transferred to adjacent subtransmission systems, the lower Mornington Peninsula system has very limited transfer capability as described below: o For the TBTS-DMA system which supplies DMA, RBD and STO zone substations, neither RBD nor STO has any transfer capability to be off-loaded. Only DMA zone substation can be off-loaded to MTN and HGS. o For the DMA-RBD system which supplies RBD and STO zone substations, only RBD zone substation can be off-loaded to DMA. DMA, however, is a single transformer zone substation and has limited spare capacity. With significant population growth (higher than the UE average) and increased electrical demand over the past decade, the area supplied by DMA, RBD and STO can no longer be considered rural. Customers in the area now expect a higher level of supply quality and reliability on par with that available in other urban regions. Unless a long-term solution is planned and implemented the Mornington Peninsula electricity reliability and quality of supply performance could degrade to an unacceptable level. 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 in the Mornington Peninsula subtransmission network. 1. Establish a new HGS-RBD 66 kv line. This includes construction of approximately 53 km of new 66 kv line from HGS to RBD zone substations at an estimated cost of $23 million. The route of the new 66 kv line is anticipated to follow along the road reserves of the south-east coast of the Mornington Peninsula, from HGS to RBD zone substation. Review by: 12/2014 Page 254 of 309

256 This option provides a number of benefits including: o Increases the system s (N) and (N-1) ratings. o Provides significant benefit for common-mode (N-2) contingency scenario for both TBTS-DMA and DMA-RBD systems. o Reduces the expected energy at risk during times of maintenance when one of the sub-transmission lines is taken out-of-service. o Improves voltage regulation in the Mornington Peninsula. o Avoids the need to underground a section of the DMA-RBD 66 kv lines near Arthur s Seat at an estimated cost of $2 million as part of bushfire mitigation, since both lines are located in close proximity to each other. 2. Establish a new TBTS-RBD 66 kv line. This option includes construction of approximately 56 km of new 66 kv line from TBTS to RBD zone substation at an estimated cost of $25 million. 3. Establish a new HGS-STO 66 kv line. This option includes construction of approximately 68 km of new 66 kv line from HGS to STO zone substations at an estimated cost of $31 million. Acquiring a suitable line route for the RBD-STO section appears to be challenging. 4. Establish a new HGS-DMA 66 kv line with DMA-RBD 66 kv line reconductoring. This option includes construction of approximately 22 km of new HGS-DMA line and reconductoring approximately 18 km of the DMA-RBD lines. Given the space limitations at DMA, it is expected to convert the existing 66 kv outdoor switchyard to GIS in order to accommodate the new line entry. The estimated cost of this option is approximately $24 million. 5. Upgrade the existing sub-transmission lines. This option includes reconductoring approximately 18 km of the DMA-RBD 66 kv lines and approximately 6 km of the TBTS- MTN 66 kv line at an estimated cost of $10 million. However, this option will not address the voltage collapse issue in the lower parts of Mornington Peninsula. 6. Reactive power compensation is not a technically viable option in the context of the Mornington Peninsula sub-transmission network as all the zone substations presently operate close to unity power factor during maximum demand periods. STO has already been overcompensated to minimise the risk of voltage collapse as much as possible. 7. Install embedded generation or equivalent demand side load management. At least 12 MW in December 2014, then in the order of 3 MW thereafter, connected at DMA, RBD or STO by December 2017, would be necessary to defer the augmentation and this generator would need to remain stable under fault conditions when one of the sub-transmission lines trip. Given the specific demand characteristics of the Mornington Peninsula, such generation support is predominantly anticipated during the Christmas Holiday period and long weekends. Review by: 12/2014 Page 255 of 309

257 Preferred network option(s) for alleviation of limitations As a means of managing the increasing voltage and thermal limitations in the Mornington Peninsula, UE proposes to establish a new HGS-RBD 66 kv line by December 2017 at an estimated cost of $23 million. These plans will be undertaken in the absence of commitment by interested parties to offer network support services by installing local generation or through demand-side management initiatives that would reduce address the limitations in the Mornington Peninsula sub-transmission systems. The estimated total annual cost of the preferred network option is $2.3 million. This cost provides a broad upper bound indication of the maximum contribution from UE which may be available to non-network service providers to reduce forecast demand and defer or avoid this augmentation. UE intends to undertake a detailed assessment of this limitation in a Regulatory Investment Test for Distribution (RIT-D) in the second half of 2014, to identify the preferred solution to alleviate the limitations on the TBTS-FSH-MTN-DMA-TBTS sub-transmission system. UE invites non-network service providers to submit their proposals to alleviate limitations on the TBTS-FSH-MTN-DMA-TBTS sub-transmission system. System summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. TBTS-FSH-MTN-DMA system Summer cyclic N Rating (MVA) Summer cyclic N-1 Rating (MVA) Embedded generation capacity (MW) 0.0 TBTS-FSH-MTN-DMA system % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 30.9 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) 4,881 5,431 5,959 6,922 7,935 Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 256 of 309

258 DMA-RBD-DMA system Summer cyclic N Rating (MVA) Summer cyclic N-1 Rating (MVA) 70.3 Embedded generation capacity (MW) 0.0 DMA-RBD-DMA system % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 12.1 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) RBD-STO-RBD system Summer cyclic N Rating (MVA) Summer cyclic N-1 Rating (MVA) 57.2 Embedded generation capacity (MW) 0.0 RBD-STO-RBD system % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 11.5 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 257 of 309

259 Load (A) Strategy 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-TBTS The TSTS-BU-WD-TSTS 66kV sub-transmission system supplies the Bulleen (BU) and West Doncaster (WD) zone substations in a looped arrangement. The critical limitation on this sub-transmission system is currently the TSTS-WD 66 kv line for an outage of the TSTS-BU 66 kv line. Magnitude, Probability and Impact of Loss of Load TSTS-BU-WD-TSTS is a summer-critical sub-transmission system. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the system s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 124 Forecast maximum demand against the TSTS-BU-WD-TSTS system ratings TSTS-BU-WD-TSTS Year Actual Load Forecast Load Summer (N-1) rating Summer (N) rating Review by: 12/2014 Page 258 of 309

260 The demand on the TSTS-BU-WD-TSTS sub-transmission system is expected to marginally exceed its (N-1) rating from summer However, the expected energy at risk is insignificant over the planning period. Whilst no decision has yet been made on a preferred network augmentation to alleviate emerging limitations in Bulleen and Doncaster supply areas, the establishment of a new zone substation in Templestowe (TSE) or, augmentation of DC with a fourth transformer (with some sub-transmission reinforcements) are being considered as being the most likely network options. Consequently, this sub-transmission system may need to be reinforced depending on the preferred solution to alleviate those limitations. However, the timing of this augmentation is expected to be beyond this planning period. Therefore, no major demand related augmentation is planned for this system over the next five years. System summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. TSTS-BU-WD-TSTS system Summer cyclic N Rating (MVA) Summer cyclic N-1 Rating (MVA) 93.2 Embedded generation capacity (MW) 0.0 TSTS-BU-WD-TSTS system % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 0.0 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 259 of 309

261 Load (A) Strategy TSTS-DC-TBTS 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. Magnitude, Probability and Impact of Loss of Load TSTS-DC-TSTS is a summer-critical sub-transmission system. The figure below depicts the historical actual maximum demands, 10% PoE summer maximum demand forecast together with the system s operational cyclic (N) rating (all plant in-service) and the (N-1) rating. Figure 125 Forecast maximum demand against the TSTS-DC-TSTS system ratings TSTS-DC-TSTS Year Actual Load Forecast Load Summer (N-1) rating Summer (N) rating The demand on the TBTS-DC-TBTS sub-transmission system is expected to exceed its (N-1) rating from However, the expected energy at risk is insignificant over the planning period. Whilst no decision has yet been made on a preferred network augmentation to alleviate emerging limitations in Bulleen and Doncaster supply areas, the establishment of a new zone substation at Templestowe (TSE) or, augmentation of DC with a fourth transformer (with some sub-transmission reinforcements) are being considered as being the most likely network options. Consequently, this sub-transmission system may need to be reinforced depending on the preferred solution to alleviate those limitations. However, the timing of this augmentation is expected to be beyond this planning period. Therefore, no major demand related augmentation is planned for this system over the next five years. Review by: 12/2014 Page 260 of 309

262 System summary The table below provides more detailed data on the station ratings, demand forecast, energy at risk, expected unserved energy and the value to customers of the expected unserved energy. TSTS-DC-TSTS system Summer cyclic N Rating (MVA) Summer cyclic N-1 Rating (MVA) 93.2 Embedded generation capacity (MW) 0.0 TSTS-DC-TSTS system % PoE summer maximum demand (MVA) Power factor Number of hours where 95% of peak load is expected Load transfer capability (MVA) 20.8 N-1 energy at risk at 10% PoE demand (MWh) N-1 expected hours at risk at 10% PoE demand (hours) N-1 expected energy at risk at 10% PoE demand (kwh) Expected unserved energy at 10% PoE demand ($k) Review by: 12/2014 Page 261 of 309

263 6.9.3 Distribution feeders Under probabilistic planning, distribution feeders are generally loaded up to 85% utilisation before they are considered for augmentation as this represents a typical trigger-point at which most augmentations become economic. Utilisation factor describes the ratio of the feeder maximum demand to the summer cyclic rating (N) under normal operating conditions. For a 10% PoE in summer , 15 feeders are expected to exceed their (N) cyclic rating with a further 92 feeders exceeding 85% of their rating. The following table provides information regarding critical limitations, where network solutions to alleviate those limitations are likely to be economic. Table 20 Distribution feeder limitations Feeder Bulk supplies Utilisation factor (%) Terminal station Zone substation BH 23 Ringwood (RWTS) Box Hill (BH) 98% 101% BR 01 Heatherton (HTS) Beaumaris (BR) 93% 94% BR 09 Heatherton (HTS) Beaumaris (BR) 92% 94% BU 06 Templestowe (TSTS) Bulleen (BU) 92% 94% CFD 22 Malvern (MTS) Caulfield (CFD) 98% 102% CRM 13 Cranbourne (CBTS) Carrum (CRM) 83% 87% CRM 21 Cranbourne (CBTS) Carrum (CRM) 96% 100% CRM 35 Cranbourne (CBTS) Carrum (CRM) 90% 94% DMA 12 Tyabb (TBTS) Dromana (DMA) 99% 103% DN 07 East Rowville (ERTS) Dandenong (DN) 92% 113% DN 11 East Rowville (ERTS) Dandenong (DN) 97% 101% DVY 24 East Rowville (ERTS) Dandenong Valley (DVY) 82% 86% FSH 12 Tyabb (TBTS) Frankston South (FSH) 98% 101% FSH 33 Tyabb (TBTS) Frankston South (FSH) 98% 101% FTN 23 Cranbourne (CBTS) Frankston (FTN) 89% 93% HGS 22 Tyabb (TBTS) Hastings (HGS) 90% 93% HGS 33 Tyabb (TBTS) Hastings (HGS) 89% 92% LD 02 East Rowville (ERTS) Lyndale (LD) 97% 101% LD 06 East Rowville (ERTS) Lyndale (LD) 88% 92% LD 33 East Rowville (ERTS) Lyndale (LD) 91% 94% Review by: 12/2014 Page 262 of 309

264 Feeder Bulk supplies Utilisation factor (%) Terminal station Zone substation MR 22 Heatherton (HTS) Moorabbin (MR) 98% 100% MR 24 Heatherton (HTS) Moorabbin (MR) 98% 100% MTN 31 Tyabb (TBTS) Mornington (MTN) 87% 90% MTN 35 Tyabb (TBTS) Mornington (MTN) 99% 102% NB 14 Heatherton (HTS) North Brighton (NB) 94% 103% OAK 23 Malvern (MTS) Oakleigh (OAK) 94% 97% OR 04 Malvern (MTS) Ormond (OR) 95% 98% OR 06 Malvern (MTS) Ormond (OR) 87% 91% OR 12 Malvern (MTS) Ormond (OR) 91% 94% SR 13 Heatherton (HTS) Sandringham (SR) 103% 105% SR 23 Heatherton (HTS) Sandringham (SR) 99% 101% STO 12 Tyabb (TBTS) Sorrento (STO) 92% 95% Proposed solutions 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. The most appropriate option is selected based on practical feasibility and least lifecycle cost. The table below identifies the preferred network solution (in the absence of any commitment by interested parties to offer network support services through demand side management) and an estimate reduction in forecast maximum demand that would be required to defer augmentation by a period of twelve months. Review by: 12/2014 Page 263 of 309

265 Table 21 Preferred network solution Feeder limitation Preferred network solution Indicative timing BH 23 Extend BH 23 by approximately 0.5 km to create a new BH 23 BH 21 tie-line. Once the feeder is extended, BH 23 will be offloaded onto BH 21. A load reduction or new generation, in the order of 0.5 MW or more, is expected to delay the augmentation by twelve months. The preferred location for network support is in the area supplied by BH 23. Dec 2014 BU 06 Upgrade BU 06. A load reduction or new generation, in the order of 0.5 MW or more, is expected to delay the augmentation by twelve months. The preferred location for network support is in the area supplied by BU 06. Dec 2014 CFD 22 Offload CFD 22 to adjacent feeders to manage loading during peak load conditions. Dec 2014 CRM 21 Upgrade CRM 21. A load reduction or new generation, in the order of 0.5 MW or more, is expected to delay the augmentation by twelve months. The preferred location for network support is in the area supplied by CRM 21. Dec 2014 CRM 35 Extend CRM 24 by approximately 1.4 km to create a new CRM 24 CRM 35 tie-line. Once the feeder is extended, CRM 35 will be offloaded onto CRM 24. A load reduction or new generation, in the order of 0.5 MW or more, is expected to delay the augmentation by twelve months. The preferred location for network support is in the area supplied by CRM 35. Dec 2014 DN 07 Reconductor LD 07. Once the feeder is upgraded, DN 07 will be offloaded onto LD 07. A load reduction or new generation, in the order of 1.0 MW or more, is expected to delay the augmentation by twelve months. The preferred location for network support is the area supplied by DN 07. DN 11 Upgrade DN 11. Establish network support agreement with embedded generator connected to DN 11. A load reduction or new generation, in the order of 0.5 MW or more, is expected to delay the augmentation by twelve months. The preferred location for network support is the area supplied by DN 11. Dec 2014 Dec 2014 FSH 12 FSH 33 MTN 31 Upgrade FSH 33. Once the feeder is upgraded, FSH 12 will be offloaded onto FSH 33. A load reduction or new generation, in the order of 0.5 MW or more, is expected to delay the augmentation by twelve months. The preferred location for network support is in the area supplied by FSH 12 and FSH 33. Extend MTN 31 by approximately 0.4 km to create a new MTN 24 MTN 31 tie-line. Once the feeder is extended, MTN 31 will be offloaded onto MTN 24. A load reduction or new generation, in the order of 0.5 MW or more, is expected to delay the augmentation by twelve months. The preferred location for network support is the area supplied by MTN 31. Dec 2014 Dec 2014 Review by: 12/2014 Page 264 of 309

266 Feeder limitation Preferred network solution Indicative timing MTN 35 Reconductor MTN 22. Once the feeder is upgraded, MTN 35 will be offloaded onto MTN 22. A load reduction or new generation, in the order of 0.5 MW or more, is expected to delay the augmentation by twelve months. The preferred location for network support is in the area supplied by MTN 35. Dec 2014 OAK 23 Upgrade OAK 23. A load reduction or new generation, in the order of 0.5 MW or more, is expected to delay the augmentation by twelve months. The preferred location for network support is in the area supplied by OAK 23. Dec 2014 SR 13 SR 23 BR 01 BR 09 CRM 13 DMA 12 DVY 24 Offload SR 13 and SR 23 onto adjacent feeders by installing automated switches. A load reduction or new generation, in the order of 1.0 MW or more, is expected to delay the augmentation by twelve months. The preferred location for network support is in the area supplied by SR 13 and SR 14. Upgrade BR 01 feeder exit cable to increase feeder capability. Once the feeder is upgraded, BR 09 can be offloaded onto BR 01 during emergencies. A load reduction or new generation, in the order of 0.5 MW or more, is expected to delay the augmentation by twelve months. The preferred location for network support is in the area supplied by BR 01 and BR 09. Upgrade CRM 13 by December This project is initiated to increase transfer capability as adjacent feeders are well utilised. A load reduction or new generation, in the order of 0.5 MW or more, is expected to delay the augmentation by twelve months. The preferred location for network support is the area supplied by CRM 13. Establish new high voltage feeders from Dromana (DMA) zone substation once the second transformer is installed by December Once commissioned, DMA 12 will be offloaded onto the new high voltage feeder. A load reduction or new generation, in the order of 0.5 MW or more, is expected to delay the overload by twelve months. The preferred location for network support is the area supplied by DMA 12. Establish new high voltage feeders from Dandenong Valley (DVY) zone substation. Once commissioned, DVY 24 will be offloaded onto the new high voltage feeder. DVY 24 supplies a rapidly growing industrial area that requires reinforcement in the next two to three years. A load reduction or new generation, in the order of 0.5 MW or more, is expected to delay the augmentation by twelve months. The preferred location for network support is the area supplied by DVY 24. Dec 2014 Dec 2015 Dec 2015 Dec 2015 Dec 2015 FTN 23 Reconductor FTN 23. A load reduction or new generation, in the order of 0.5 MW or more, is expected to delay the augmentation by twelve months. The preferred location for network support is the area supplied by FTN 23. Dec 2015 Review by: 12/2014 Page 265 of 309

267 Feeder limitation HGS 22 HGS 33 Preferred network solution Establish new high voltage feeders from Hastings (HGS) zone substation. Once commissioned, HGS 22 and HGS 33 will be offloaded onto the new high voltage feeder. A load reduction or new generation, in the order of 1.0 MW or more, is expected to delay the augmentation by twelve months. The preferred location for network support is the area supplied by HGS 22 and HGS 33. Indicative timing Dec 2015 LD 02 Reconductor LD 02. A load reduction or new generation, in the order of 0.5 MW or more, is expected to delay the augmentation by twelve months. The preferred location for network support is the area supplied by LD 02. Dec 2015 LD 06 LD 33 MR 22 MR 24 NB 14 OR 04 OR 06 OR 12 STO 12 Establish new high voltage feeder from Lyndale (LD) zone substation. Once commissioned, LD 06 and LD 33 will be offloaded on to the new high voltage feeder. A load reduction or new generation, in the order of 1.0 MW or more, is expected to delay the augmentation by twelve months. The preferred location for network support is the area supplied by LD 06 or LD 33. Establish a new high voltage feeder from MR zone substation. Once commissioned, MR 22 and MR 24 will be offloaded onto the new high voltage feeder. A load reduction or new generation, in the order of 0.5 MW or more, is expected to delay the augmentation by twelve months. The preferred location for network support is the area supplied by MR 22 and MR 24. Establish a new high voltage feeder from Elwood (EW) zone substation. Once commissioned, NB 14 will be offloaded onto the new high voltage feeder. A load reduction or new generation, in the order of 0.5 MW or more, is expected to delay the augmentation by twelve months. The preferred location for network support is the area supplied by NB 14. Upgrade OR feeders. A load reduction or new generation, in the order of 0.5 MW or more, is expected to delay the augmentation by twelve months. The preferred location for network support is the area supplied by OR 04, OR 06 and OR 12 feeders. Extend RBD 11 to create a new RBD 11 STO 12 tie-line. Once the feeder is extended, STO 12 will be offloaded onto RBD 11. A load reduction or new generation, in the order of 0.5 MW or more, is expected to delay the augmentation by twelve months. The preferred location for network support is the area supplied by STO 12. Dec 2015 Dec 2015 Dec 2015 Dec 2015 Dec 2016 UE plans to undertake network augmentations to alleviate limitations on the abovementioned distribution feeders, in the absence of any commitment by interested parties to offer network support services that would alleviate those limitations. UE invites non-network service providers to submit their proposals to alleviate limitations on these distribution feeders. Review by: 12/2014 Page 266 of 309

268 7 Demand side management UE is committed to delivery of long-term supply reliability to customers. UE also recognises that it is imperative to ensure electricity is delivered in an efficient, economic and environmentally responsible manner. Therefore, UE s network development and planning involves the process of selecting technically and economically accepted projects whether they are network or non-network solutions. UE defines non-network projects or programmes undertaken to meet customer demand by shifting or reducing demand in some way, rather than increasing supply capacity through network augmentation. To this end, UE has undertaken the following actions to promote non-network proposals in the last twelve months: UE has notified and invited submissions from various stakeholders, including industry participants, customers, interested parties and non-network service providers on present and emerging network limitations identified in this DAPR and previous Distribution System Planning Reports (DSPR). UE has actively engaged with non-network service providers to identify and quantify nonnetwork solutions to address emerging network constraints. UE has facilitated non-network initiatives with the establishment of Memorandum of Understanding (MoU) with the City of Manningham to explore non-network solutions to achieve shared strategic objectives for more efficient energy delivery. UE is considering exploring the use of this joint planning model with other local councils or interested organisations. UE has established a Demand Side Engagement Register for customers, interest groups, industry participants and non-network service providers who wish to be regularly informed of UE s planning activities on an on-going basis. UE has published the Demand Side Engagement Document (DSED) outlining the process for engaging and consulting with non-network service providers, and for investigating, developing, assessing and reporting on non-network options as alternatives to network augmentation, under the national distribution planning and expansion framework. This document is available on UE s website at: UE recognises that early engagement is critical for successful and efficient implementation of nonnetwork solutions. In order to support non-network service providers and encourage credible nonnetwork proposals in the future, UE is committed to: Communicating with all parties on our Demand Side Engagement Register by of nonnetwork opportunities identified in this DAPR. Undertaking a public forum following the publication of this DAPR to discuss identified limitations and non-network opportunities in further detail. All parties from our Demand Side Engagement Register shall be invited to attend. Review by: 12/2014 Page 267 of 309

269 Exploring the use of joint planning models with other local councils or interested organisations to incorporate non-network options into the network planning process. Actively engage with non-network service providers to submit credible non-network proposals to address current and emerging network constraints. Investigating, developing and implementing the preferred non-network solution in accordance with our Demand Side Engagement Document. Exploring the use of Demand Management Incentive Scheme (DMIS), 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 currently being 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. 7.1 Current initiatives and projects Doncaster Hill 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. 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 establish a new 66/22 kv zone substation in Templestowe or a fourth transformer at the Doncaster zone substation. DMIS funding has been used to explore options with Council to manage maximum demand and potentially defer network augmentations. The joint planning identified a commercially viable nonnetwork solution in the form of a district energy services scheme 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 district energy services scheme on Doncaster Hill with an objective to defer planned network augmentations in the Doncaster area. Both service providers concluded that such a scheme was commercially viable. UE plans to continue discussions and commercial negotiations in the lead-up to the future RIT-D to maximise the opportunity for a viable, competitive non-network solution to defer the planned network augmentation and address this emerging network constraint. Review by: 12/2014 Page 268 of 309

270 7.1.2 Virtual Power Plant trial UE is progressing with the pilot trial of the Virtual Power Plant (VPP) project. As part of this project, UE intends to install and operate a small number of distributed generations (with storage facilities) within residential customer premises to reduce the maximum demand on the network. UE plans to monitor this development to determine if there is a potential migration path to a more localised demand management strategy in the future. This project is in its early stage, and is funded through DMIS. With the rapidly falling price of solar PV and battery storage, UE is eager to explore the use of solar PV and controlled battery storage technology to develop an incremental approach to addressing immediate capacity shortfalls and defer traditional network augmentation solutions which by comparison, provided a much larger step-change in available capacity.. The aim of the project is to validate or otherwise, the use of a VPP to manage embedded generation and storage in a residential setting for the provision of efficient and prudent non-network augmentation. Review by: 12/2014 Page 269 of 309

271 8 Network performance 8.1 Network reliability Reliability performance indicators 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 Reliability performance targets UE s reliability performance targets for this regulatory period have been set by the Australian Energy Regulator (AER). 17 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 22 below provides UE s reliability performance targets for the current regulatory period. Table 22 Reliability performance target levels UE reliability performance SAIDI unplanned (minutes) SAIFI unplanned (interruptions) MAIFIe unplanned (interruptions) CAIDI unplanned (minutes) The current EDPR period is 2011 to 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. Review by: 12/2014 Page 270 of 309

272 8.1.3 Reliability performance Recent reliability performance The largest influence on the variability of the network performance is the environment in which UE operates. UE s network is predominantly overhead and has experienced an increase in weather related events resulting in large variations in the year to year performance of the network. UE has also experienced an increasing trend in equipment failure as an increasing number of assets are approaching their end of life. Figure 126 shows the major causes of supply interruption on the distribution network. 18 Figure 126 Causes of supply interruption Faults by cause 13% 11% 7% 15% 6% 48% Weather Vegetation Equipment failure Third party incidents Other Animals Figure 127 shows the impact of equipment failure events on reliability in recent times. Figure 127 Impact of equipment failure on reliability 18 UE: 2012 Regulatory Information Notice (RIN). Review by: 12/2014 Page 271 of 309

273 SAIDI Strategy SAIDI - Plant Failure y = 1.13x SAIDI 90th Percentile 10th Percentile Linear (SAIDI) The charts above show that the major cause of supply interruptions on UE network is equipment failure and its impact on reliability has increased in recent times. The increasing trend in equipment failure events is mainly attributed to an increasing number of assets approaching their end of economic 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 (or saturate) 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 outcomes to ensure that only prudent and effective expenditures are made. Details of significant asset replacement programmes are outlined in Section 9.3. Figure 128 shows the impact of weather related events on reliability in recent times. Review by: 12/2014 Page 272 of 309

274 SAIDI Strategy Figure 128 Impact of weather and vegetation related events on reliability SAIDI - Weather & Vegetation y = 1.09x SAIDI 90th Percentile 10th Percentile Linear (SAIDI) Figure 126 and Figure 128 shows that although weather and vegetation related supply interruptions are minor, their impact on reliability has increased in recent times. In order to minimise the impact of vegetation on reliability, UE undertakes vegetation management to maintain adequate clearance around the overhead network, in accordance with Electric Line Clearance Regulations 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. Reliability performance in 2013 In 2013, UE customers are forecast to experience worse than expected reliability performance targets. The causes of poor network performance for 2013 are identified as: Increased vegetation and weather related events despite aggressive vegetation management. Increased number of equipment failure events. Poorer than expected restoration times. Reliability performance forecasts 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. Review by: 12/2014 Page 273 of 309

275 The following table shows the forecast network performance for the remainder of the current regulatory period to Table 23 Reliability performance forecasts UE reliability performance forecasts SAIDI unplanned (minutes) SAIFI unplanned (interruptions) MAIFIe unplanned (interruptions) CAIDI unplanned (minutes) UE reliability performance review process UE undertakes a monthly review of the reliability performance during the previous month and on a rolling 12 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 improve reliability. 20 Identify management strategies to improve reliability. The aim of these reviews is to improve the reliability to our customers in a strategic, targeted, and cost-effective manner Network improvement 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. The following provides a summary of the major reliability improvement initiatives: 19 The forecast network performance is based on current and historic performance, proposed initiatives and projects. 20 The worst performing high voltage feeders on a rolling 12-month basis are classified as rogue feeders and are targeted for improvements. Review by: 12/2014 Page 274 of 309

276 Asset replacement programmes In addition to the reliability improvement programmes, UE is increasing 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. Expanded pole top inspection programme and pole top replacement. Sub-transmission line refurbishment and replacement. Substation primary plant condition based replacement. 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 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. Pole fire mitigation UE has identified and ranked high-risk assets and geographical locations by studying critical factors contributing to pole fire ignition. UE s long term programme is to inspect and tighten or replace end-of-life poles and pole top structures at critical sites over a number of years. UE is currently trialling the Early Fault Detection (EFD) system on a high voltage feeder designated in the High Bushfire Risk Area (HBRA) to detect potential modes of asset failure that leads to pole fires. UE forecasts pole fire mitigation programme to increase in volume as external environmental factors result in climatic conditions conducive to pole fires. Remote control and monitoring of field switches UE propose to continue installing 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. Review by: 12/2014 Page 275 of 309

277 8.1.6 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 24 Network performance indicators submitted to the AER UE reliability performance SAIDI unplanned (minutes) SAIFI unplanned (interruptions) MAIFIe unplanned (interruptions) CAIDI unplanned (minutes) Review by: 12/2014 Page 276 of 309

278 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. UE is working to ensure that all customer supply is within the specified regulatory ranges for all power quality measures. 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 steady state overvoltages. 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 5 th harmonic current created by power electronic equipment Power quality regulatory requirements UE is required to comply with Section 4 of the Victorian Electricity Distribution Code (The Code) and Schedule 5.1 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 25 to Table 27. Review by: 12/2014 Page 277 of 309

279 Table 25 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% % / -10% Medium voltage (66 kv) +10% / -10% +10% / -10% Table 26 Allowable voltage unbalance limits Voltage levels The Code 22 NER Low voltage (less than 1 kv) 1% 1% Medium voltage (1 kv to 22 kv) 1% 2% Medium voltage (66 kv) 1% 2.5% Table 27 Allowable voltage total harmonic distortion limits Voltage levels The Code NER Low voltage (less than 1 kv) 5% 23 8% Medium voltage (1 kv to 22 kv) 3% 24 8% Medium voltage (66 kv) 3% 7 8% Power quality strategy 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 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, 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. 21 Voltage variation of +10%, -10% is applicable for rural areas. 22 Voltage unbalance can be 2% for a total of 5 minutes in every 30 minute period. 23 4% of odd individual voltage harmonic distortion and 2% of even individual voltage harmonic distortions are allowed. 24 2% of odd individual voltage harmonic distortion and 1% of even individual voltage harmonic distortions are allowed. Review by: 12/2014 Page 278 of 309

280 This approach provides a proactive framework for monitoring and addressing power quality issues on the network. UE s aim is to: Maintain power quality levels within regulatory requirements. 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 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 129. Review by: 12/2014 Page 279 of 309

281 Figure 129 The present coverage of PQ monitors on UE network PQ monitors at all zone substation s No PQ monitors at transmissi on connection points PQ monitors at some large customer connections No PQ monitors at distribution substations PQ monitors at end of the longest HV feeder from each zone substation Smart meters at all <160MWh customer connection points 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. Review by: 12/2014 Page 280 of 309

282 Table 28 PQ measurement capability of installed power quality monitors PQ disturbances Zone substation End of feeder 25 AMI meters Steady state voltages 26 Voltage sags and swells Under / over voltages Transient Voltage unbalance Harmonics Flicker 29 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 next five years, by: Installing power quality monitors at each transmission connection points. Installing power quality monitors at selected large customers. Installing power quality monitors on targeted high voltage feeders (not necessarily the longest feeder) 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 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. 25 Includes large customers. 26 Only maximum and minimum voltages. 27 Total Harmonic Distortion (THD) and Individual HD. 28 THD only. 29 Not all zone substations. Review by: 12/2014 Page 281 of 309

283 The survey is conducted annually, and is heavily reliant on power quality monitoring data. 30 The LTNPQS provides analysis of steady state voltages, voltage harmonics, voltage unbalance and voltage sags 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 LTNPQS 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 Power quality performance Steady state voltage Power quality monitoring has revealed that in some instances the steady state supply voltage is outside the regulatory limits. UE has also identified during the current rollout of AMI metering 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 the growing smart meter population. 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 LTNPQS results, about 24% of the low-voltage sites exceed the upper voltage limit of 1.1 per unit, while 27% of the medium-voltage sites exceed the upper voltage limit of 1.06 per unit as shown in the figures below UE has provided data from 46 low-voltage sites and 62 medium-voltage sites. 31 UE has supplied data for 64 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 LTNPQS utility and national results. Review by: 12/2014 Page 282 of 309

284 UE00032 UE00048 UE00049 UE00021 UE00020 UE00028 UE00042 UE00006 UE00146 UE00043 UE00002 UE00015 UE00046 UE00008 UE00033 UE00039 UE00034 UE00029 UE00155 UE00149 UE00051 UE00018 UE00031 UE00025 UE00144 UE00038 UE00148 UE10005 UE10006 UE10002 UE10001 UE00052 Voltage (p.u) UE00124 UE00098 UE00110 UE00127 UE00135 UE00107 UE00152 UE00133 UE00105 UE00134 UE00115 UE00129 UE00136 UE00112 UE00121 UE00117 UE00143 UE00102 UE00108 UE00131 UE00101 UE00139 UE00141 UE00125 UE00137 UE00119 UE00132 UE00103 UE00100 UE00104 UE00128 UE00140 UE00123 UE00113 UE00156 UE00126 UE00111 UE00142 UE00120 UE00114 UE00138 UE00122 UE00118 UE00106 UE00130 UE00109 Voltage (p.u) Strategy Figure 130 Steady state voltage distribution for LV sites during (Financial year) Site Figure 131 Steady state voltage distribution for MV sites during (financial year) Site To proactively respond to this, UE intends to query the AMI metering by exception, reporting only those customers outside the regulatory limits. These customers will then be aggregated by common asset class to determine if the voltage problems are occurring in clusters. UE will then remedy 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. Review by: 12/2014 Page 283 of 309

285 UE00139 UE00127 UE00156 UE00134 UE00131 UE00152 UE00143 UE00098 UE00118 UE00106 UE00112 UE00123 UE00130 UE00133 UE00101 UE00142 UE00141 UE00102 UE00109 UE00110 UE00119 UE00113 UE00103 UE00128 UE00126 UE00122 UE00121 UE00114 UE00120 UE00138 UE00129 UE00100 UE00117 UE00125 UE00137 UE00140 UE00107 UE00124 UE00108 UE00115 UE00104 UE00135 UE00132 UE00136 UE00105 UE00111 VUF (%) Strategy Compensating the reactive power by installation of pole mounted capacitor banks. Installing voltage regulators along heavily loaded long lines. Augmenting the low voltage network (low voltage feeder or distribution substations). Augmenting the high voltage network (high voltage feeder). Undertaking high-voltage or low-voltage open point changes or load balancing Voltage unbalance Voltage unbalance is known to cause overheating in transformers and customer motors due to negative-sequence components created in the unbalance. According to the LTNPQS results, the voltage unbalance at all monitored UE sites are below 2%, thus complying with the requirements of the NER. However, some UE sites are noncompliant 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 132 Voltage unbalance distribution for LV sites during (Financial year) Site Review by: 12/2014 Page 284 of 309

286 UE00113 UE00152 UE00104 UE00121 UE00126 UE00102 UE00131 UE00141 UE00098 UE00115 UE00128 UE00117 UE00103 UE00143 UE00110 UE00108 UE00118 UE00100 UE00136 UE00114 UE00101 UE00130 UE00106 UE00137 UE00111 UE00123 UE00107 UE00156 UE00135 UE00127 UE00109 UE00119 UE00122 UE00105 UE00133 UE00142 UE00112 UE00125 UE00140 UE00120 UE00124 UE00134 UE00139 UE00129 UE00138 UE00132 THD (%) UE00039 UE00042 UE00053 UE00027 UE00155 UE00016 UE00148 UE00018 UE00032 UE00151 UE00034 UE00150 UE00149 UE00031 UE00014 UE00050 UE00045 UE00008 UE00051 UE00023 UE10004 UE00030 UE00003 UE00046 UE00028 UE00004 UE00022 UE00019 UE00017 UE00043 UE00025 UE00147 UE00144 UE00002 UE00026 UE00024 UE00145 UE00037 UE10003 UE00029 UE10005 UE00009 UE00006 UE00001 UE00038 UE00010 UE00011 UE00033 UE00013 UE00154 VUF (%) Strategy Figure 133 Voltage unbalance distribution for MV sites during (Financial year) Site The worst performing zone substations for unbalance include those that supply rural areas where supplies may be provided via two-phase or SWER systems Voltage harmonic distortion Voltage harmonic distortion can vary significantly across the network. According to the LTNPQS results, the voltage harmonic distortion at some monitored UE sites are not within the regulatory limits. To comply with the regulatory requirements, UE has a programme of installing harmonic filters at non-compliant zone substations. Figure 134 Voltage harmonic distortion for LV sites during (Financial year) Site Review by: 12/2014 Page 285 of 309

287 UE00013 UE00021 UE00026 UE00017 UE00144 UE00145 UE00148 UE00028 UE00051 UE00050 UE00031 UE10004 UE00053 UE00001 UE00015 UE00016 UE00154 UE00018 UE00049 UE00048 UE00010 UE00014 UE00027 UE00019 UE00147 UE00037 UE00043 UE00004 UE00011 UE00030 UE00146 UE00042 UE00155 UE00023 UE00025 UE00036 UE00003 UE00022 UE00039 UE00151 UE00150 UE00002 UE10003 UE00045 UE00024 UE00046 UE00008 UE10005 UE00020 UE00047 THD (%) Strategy Figure 135 Voltage harmonic distortion for MV sites during (Financial year) Site UE has observed fuse operations of capacitor banks on the network which is directly attributed to harmonic resonance. Harmonic resonance can occur between capacitor banks and network reactance when the resonance frequency coincides with a harmonic frequency generated by nonlinear loads. UE has identified a number of problematic sites and is in the process of installing various combinations of harmonic filtering and detuning reactors to address these issues Voltage sag 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 LTNPQS results, the voltage sag SAIFI 32 at all monitored UE sites are within the LTNPQS limit. 32 The index used in the LTNPQS reports to assess sags. Review by: 12/2014 Page 286 of 309

288 UE00016 UE00053 UE00050 UE00039 UE00155 UE00036 UE00031 UE00008 UE00154 UE00038 UE00024 UE00046 UE00019 UE00150 UE10001 UE00028 UE10006 UE00030 UE00027 UE00004 UE00020 UE00003 UE10002 UE00047 UE00051 UE10007 UE00018 UE00151 UE00148 UE00149 UE10004 UE00043 UE00015 UE00021 UE00052 UE00049 UE00022 UE00001 UE00010 UE00011 UE00033 UE00026 UE00048 UE00042 UE00146 UE00045 UE00002 UE00034 Sag SAIFI UE00143 UE00152 UE00138 UE00134 UE00132 UE00111 UE00139 UE00104 UE00124 UE00119 UE00130 UE00112 UE00120 UE00098 UE00121 UE00136 UE00103 UE00118 UE00127 UE00126 UE00110 UE00114 UE00122 UE00106 UE00142 UE00131 UE00128 UE00109 UE00117 UE00108 UE00102 UE00123 UE00141 UE00140 UE00125 UE00107 UE00101 UE00137 UE00133 UE00100 UE00135 UE00115 UE00129 UE00105 UE00113 UE00156 Sag SAIFI Strategy Figure 136 Voltage sag SAIFI distribution for LV sites during (Financial year) Site Figure 137 Voltage sag SAIFI distribution for MV sites during (Financial year) Site Many of the substations experiencing voltage sags are those found on the Mornington Peninsula where many long sub-transmission and distribution feeders exist, and are generally exposed to high numbers of faults per annum. 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 in the Mornington Peninsula 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. Review by: 12/2014 Page 287 of 309

289 Other power quality disturbances Voltage swells The majority of the over-voltage complaints by customers relate to steady state over-voltage rather than temporary over-voltages. Temporary over-voltages are usually a result of an HV injection where a high-voltage conductor may fall onto a low-voltage conductor during a storm (for example). When complaints are received, investigations and any required resolution is treated as a matter of priority. Transient voltage Switching transients, particularly those generated by capacitor bank switching and auto-reclose operations, is becoming an emerging issue over the last few years. UE has had feedback from customers impacted by switching transients through reported complaints of intermittent malfunctioning equipment. UE will investigate optimising capacitor bank switching setting to minimise the number of switching operations required for power factor correction Power quality initiatives UE plans to undertake a number of initiatives in the area of power quality. The initiatives include: 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 SPI PowerNet and be progressively rolled-out over the next five years. Develop AMI power quality metering The progressive rollout of AMI meters enables UE to monitor basic power quality levels at individual customer premises. UE is developing 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. 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. Low voltage regulator trial Many renewable energy generators (such as roof-top solar photovoltaic panels and wind) are intermittent in their power output. This brings with it a need to investigate localised impacts on network flicker and steady-state voltage profiles. Review by: 12/2014 Page 288 of 309

290 Application of a low-voltage regulators can potentially tighten voltage spread and provide faster response to sudden changes in voltage. They will 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 voltage towards the bottom of the regulatory voltage band. At present, the range of sizes for this equipment is limited and they will be limited in their use to specific areas of the low voltage networks. Nevertheless, the devices will be trialled in areas of the low voltage network 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. Bus-tie open scheme This scheme limits the severity of voltage sags created by faults on the HV 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-sag 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. Detuning reactor installation In recent times, UE has observed plant damage on the network which is directly attributed to harmonic resonance. Detuning reactors eliminate potentially damaging resonance conditions. UE intends to retrofit detuning reactors to existing capacitor banks in zone substations, starting with the network that has observed plant damage due to harmonic resonance, followed by substations where modelling and/or measurements suggest an emerging issue. Review by: 12/2014 Page 289 of 309

291 9 Life cycle asset management planning 9.1 Asset management strategy Effective asset management planning transforms UE s strategic intent into optimal decisions and actions that deliver safe, efficient and reliable delivery of essential services that meet customers and stakeholders current and future needs. UE is committed to maximising the long-term value of our stakeholders investment in a legally and environmentally compliant, safe and sustainable manner through a structured framework for stewardship of the network over its total life cycle. The following key asset management objectives have been set to ensure that corporate requirements are met: Employ good industry asset management practice to prudently manage the assets over the total life cycle, without compromising the health and safety of our employees, stakeholders or the public. Ensure compliance with applicable laws, rules and regulations. Undertake all activities and execute our obligations in adherence to Good Industry Practice. Be prudent and efficient in the deployment of capital to optimise the performance of the business in the long term for the benefit of all stakeholders. Prudently manage reasonably foreseeable and credible hazards and risks to As Low as Reasonably Practicable (ALARP) by maintaining a robust and transparent framework to ensure a systematic and strategic approach for the continual identification, management and mitigation of risk. Build our reputation with customers and key stakeholders by striving for innovation, reliability, safety and excellent customer service in the face of increasing customer and community expectations. Undertake continuous improvement, through constant and timely review of Asset Management practices. Engage in all relevant industry issues to ensure that the business, its stakeholders and customers positions are well understood and effectively represented to deliver superior outcomes. Review by: 12/2014 Page 290 of 309

292 9.2 Life cycle asset management process UE recognise asset management philosophy is about balance between investing in and driving value from an asset. This balance can only be achieved with a full understanding of the overall health of the network, thereby recognising that asset management philosophy would address specific asset needs at particular stages within the holistic view of an asset s life cycle. UE therefore has adopted four core life-cycle activities as outlined in Figure 138. Figure 138 The asset life cycle Design Dispose Acquire / Build Utilise UE also adopts a total cost of ownership approach which accounts for the life cycle costs during the asset s physical life. These costs are used to identify the preferred option that maximises the net present value of benefits. Table 29 Life cycle stages and related cost categories Life cycle costs Life cycle stages Design Acquire Utilise Dispose Direct cost Specifications Purchase Labour Storage Drawings Taxes Equipment Recycle Testing Shipping Maintenance Treatment Quality Checks Finance Inspection Transport Waste Disposal Review by: 12/2014 Page 291 of 309

293 Life cycle costs Life cycle stages Design Acquire Utilise Dispose Indirect cost Training Handling Delivery to job site Insurance Handling Storage Training Training Record keeping Record keeping Industrial Hygiene Analysis Licensing and permitting Planning Packaging/Disposal Record keeping Uncertain cost Spills and accidents in testing Compliance with new regulation Spills and accidents in storage and handling obsolescence Equipment failure Spills or accidents in use Occupational liabilities Compliance with new regulation Legal liabilities Health claims Obsolescence Asset design strategy (Conception/Planning/Design) UE adopts the Life Cycle Decision Making (LCDM) strategy in asset management to minimise uncertainty, identify and quantify risks and support the decision process leading to asset acquisition of major network investments. Under this strategy, UE evaluates a number of parameters including energy loss reduction that could be addressed by network augmentation and asset replacement programmes. UE adopts standard modern equivalent conductor sizes (or bigger) for replacing sub-transmission and distribution systems, or appropriate conductor sizes if there is an augmentation need which optimise the thermal current carrying capability, reduce electrical losses and meet economic criteria by minimising the overall cost to customer of the distribution of electrical energy. UE also considers converting older zone substations to operate at higher voltages to meet future customer demand. Similarly, power transformers and other electrical plants are also specified to provide adequate power capability, whilst also optimising electrical losses and overall costs to customers in accordance with industry standards Asset acquisition and building strategy This activity involves decision making about the type of capital investment required followed by the delivery of the appropriate investment programmes. The requirement for asset creation or acquisition is the result of decisions taken to: Build new networks due to subdivision development. Upgrade existing assets due to increased demand. Replace existing assets that have reached the end of their life. UE adopts a balanced approach of technology management, standardisation policy, energy loss reduction policy and end-of-life management policy into asset acquisition strategy. Review by: 12/2014 Page 292 of 309

294 9.2.3 Asset utilisation strategy (Installation/Operation/Maintenance/Repair) The asset utilisation phase of the asset lifecycle is unquestionably the longest phase of the overall asset lifecycle and represents a significant contribution to risk management, asset life, operating and maintenance costs, and improved user and community outcomes. UE s strategy for installation, operation, maintenance and repair of its assets is to comply with the legislation, guidelines and company policy for the safe and efficient operation of its assets and to minimise any disruption to the system that may occur during planned and unplanned events. Asset utilisation spans over three distinct phases in the asset s life cycle: 1. Conditioning phase characterised by high risk of failure. 2. Normal usage phase characterised by stable operation with low risk of failure. 3. End of economic life phase characterised by high risk of failure. Figure 139 Risk profile over the asset life Asset disposal strategy As a key part of the lifecycle management of its assets, UE continuously reviews the effectiveness of its assets, at the individual level and collectively as asset systems, and assesses whether they remain fit for purpose. A number of factors are considered when the decision is made to dispose of or rationalise assets. Key considerations are: Assets considered to be unfit for purpose due to environmental impact and other risk assessments. Changes to design and maintenance standards. Review by: 12/2014 Page 293 of 309

295 Assets at the end of their economical lives, those which are no longer supported by manufacturers. Emergency spares requirements Asset replacement programme Summary of planned replacement projects The table below summarises the proposed projects that are to address asset replacement or refurbishment needs over the next five years. 34 Table 30 Proposed asset replacement / refurbishment programme Project description Indicative Timing Doncaster pillar replacement project 2013 to 2018 Ormond (OR) 11 kv switchboard replacement 2013 to 2014 Surrey Hills (SH) 6.6 kv switchboard replacement 2013 to 2014 Burwood (BW) No.2 transformer replacement Dec 2014 Gardiner (K) relay replacement 2014 to 2015 West Doncaster (WD) No.2 transformer replacement Dec 2015 Burwood (BW) No.1 transformer replacement Dec 2015 Dandenong South (DSH) No.3 transformer replacement Dec 2015 Heatherton (HT) No.3 transformer replacement Dec 2015 Mordialloc (MC) No.1 transformer replacement Dec 2015 Dandenong South No.2 transformer replacement Dec 2016 Dandenong (DN) No.1 transformer replacement 2016 to 2018 Frankston South (FSH) relay replacement 2016 to 2019 Mordialloc (MC) No.2 transformer replacement Dec 2016 North Brighton (NB) switchboard replacement 2015 to 2016 Mulgrave (MGE) relay replacement 2016 to Assets that are close to their end of economic life are refurbished prior to relocating to critical parts of the network as emergency spares. 34 The replacement programme includes planned investments with an estimated capital cost of $2 million or more. Review by: 12/2014 Page 294 of 309

296 Project description Indicative Timing Noble Park (NP) No.1 transformer replacement Dec 2016 Oakleigh East (OE) relay replacement 2016 to 2017 Dandenong South (DSH) No.1 transformer replacement Dec 2017 Mentone (M) No.2 transformer replacement Dec 2017 Gardiner (K) 11 kv switchboard replacement 2017 to 2020 Surrey Hill (SH) No.1 and No.3 transformer replacement 2017 to Impact on network limitations The age profile of UE s distribution network reflects the large investment that took place between 1950s and 1970s. The present implication is that an increasing population of aged zone substation transformers and switchboard require replacement over the next five years. Additionally, this network expansion was at a time when the south-eastern suburbs and the Mornington Peninsula was predominantly rural land. Much of this area is now urbanised, resulting in projects that upgrade the network to current modern equivalent standards to address the expectation of urban customers such as high voltage feeder works to enhance reliability in this area. UE has identified a number of network limitations in Section 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 Mordialloc (MC) transformers by December Replace North Brighton (NB) 11 kv switchboard by December Replace Frankston South (FSH) No.1 transformer by December 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 are proposed to be replaced over the next five years, the magnitude of the expected energy at risk is expected to be higher than the numbers presented in Section Review by: 12/2014 Page 295 of 309

297 10 Advanced Metering Infrastructure 10.1 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 ( 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. The Victorian Government has 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) has been 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 UE s budget application for the AMI roll out for the 2012 to 2015 period, as required by the CROIC, was approved by the AER in November From January 2016, the economic regulatory arrangements for metering will be determined by the AER as part of the five yearly electricity price review cycle that regulates the pricing for UE s distribution use of system tariffs. Review by: 12/2014 Page 296 of 309

298 10.2 AMI programme The Government mandate requires UE to: Deploy approximately 650,000 AMI meters. 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 program AMI solution UE s AMI programme has undertaken 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 140 UE s AMI solution The UE AMI programme has 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 in North America. Information systems are based on purchased software and leading systems integration companies were involved in the implementation. Review by: 12/2014 Page 297 of 309

299 10.4 Investment in metering Table 31 provides UE s investment in metering which occurred in 2012, and planned investments in metering over the next five years. 35 Table 31 Financial summary of investment in metering ($, million) Metering N/A N/A Information technology N/A N/A Communication N/A N/A The data provided above is a summary of the information provided to the AER as part of UE's 2014 Revised AMI Charges Application, submitted on 30 August UE has not attempted to estimate the investments in metering beyond Investments are provided on calendar year basis. 36 In nominal value 37 In real value (2013 Australian dollar) 38 See Review by: 12/2014 Page 298 of 309

300 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 DSED Demand Side Engagement Document DSPR Distribution System Planning Report 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 NPV Net Present Value Review by: 12/2014 Page 299 of 309

301 PoE Probability of Exceedance RIT-D Regulatory Investment Test for Distribution RIT-T Regulatory Investment Test for Transmission SPIE SPI Electricity Pty Ltd TCPR Transmission Connection Planning Report UE United Energy Distribution Pty Ltd VCR Value of Customer Reliability Review by: 12/2014 Page 300 of 309

302 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 Review by: 12/2014 Page 301 of 309

303 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. Review by: 12/2014 Page 302 of 309

304 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 of the 2013 TCPR explains that pursuant to clause (d) of the National Electricity Rules, the TCPR presents the information on transmission connection planning required under schedule 5.8. Section of the 2013 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 2013 TCPR is available from United Energy s website at: Review by: 12/2014 Page 303 of 309

305 Appendix B NER Schedule Cross-References Schedule 5.8 clause Matters addressed Where information is presented in the 2013 DAPR 5.8(a) Information regarding the Distribution Network Service Provider and its network 5.8(a)(1) Description of its network Section (a)(2) Description of its operating environment Section (a)(3) The number and types of its distribution assets Section (a)(4) Methodologies used in preparing the DAPR including methodologies used to identify system limitations and any assumptions applied Section 6.1 to (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 5.3 to 5.4 Section (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 to (b)(2) Load forecasts At the transmission-distribution connection points including where applicable: Appendix A (2013 TCPR) o Total capacity o o o o o Firm delivery capacity for summer periods and winter periods 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) Power factor at time of peak load Load transfer capacities Generation capacity of known embedded generating units For sub-transmission lines including where applicable: o Total capacity Section o o Firm delivery capacity for summer periods and winter periods Peak Load (summer or winter and Review by: 12/2014 Page 304 of 309

306 an estimate of the number of hours per year that 95% of peak load is expected to be reached o o o Power factor at time of peak load Load transfer capacities Generation capacity of known embedded generating units For zone substations including where applicable: o Total capacity Section o o o o o Firm delivery capacity for summer periods and winter periods 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 Power factor at time of peak load Load transfer capacities Generation capacity of known embedded generating units Forecasts of future transmission-distribution connection points (and any associated connection assets), including for each future transmissiondistribution connection point: o Location Appendix A (2013 TCPR) o o Future loading level Proposed commissioning time (estimate of month and year) 5.8(b)(3) Forecasts of future sub-transmission systems and zone substations, including for each zone substation: Location Future loading level Proposed commissioning time (estimate of month and year) Section 6.4 Section Section (b)(4) 5.8(b)(5) Forecasts of the Distribution Network Service Provider's performance against any reliability targets in a service target performance incentive scheme. Description of any factors that may have a material impact on its network, including factors affecting: Fault levels Section Section 4.2 Section 6.9 Review by: 12/2014 Page 305 of 309

307 Voltage levels Other power system security requirements Section 8.1 Section 8.2 Section 9.4 The quality of supply to other Network Users (where relevant) Ageing and potentially unreliable assets 5.8(c) Information on system limitations for sub-transmission lines and zone substations 5.8(c)(1) 5.8(c)(2) Estimates of the location and timing (month(s) and year) of the system limitation 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 Section Section (c)(3) Impact of the system limitation, if any, on the capacity at transmission-distribution connection points 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 (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 (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) 5.8(d)(4) The types of potential solutions that may address the overload or forecast overload 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 location of relevant connection points at which the estimated reduction in forecast load would defer the overload. Review by: 12/2014 Page 306 of 309

308 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) 5.8(e)(2) 5.8(e)(3) If the regulatory investment test for distribution is in progress, the current stage in the process. A brief description of the identified need. A list of the credible options assessed or being assessed (to the extent reasonably practicable). Section (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 (where relevant) of the preferred option. 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. 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 Section 6.5 Section Section (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 (g)(2) An urgent and unforeseen network issue as described in clause (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. Section 6.8 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, Review by: 12/2014 Page 307 of 309

309 demand side options, and options involving other distribution or transmission networks. 5.8(h) The results of any joint planning undertaken with a Transmission Network Service Provider in the preceding year 5.8(h)(1) 5.8(h)(2) A summary of the process and methodology used by the Distribution Network Service Provider and relevant Transmission Network Service Providers to undertake joint planning. 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. Appendix A (2013 TCPR) 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) 5.8(i)(2) A summary of the process and methodology used by the Distribution Network Service Providers to undertake joint planning. 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 Section 6.1 to 6.2 Section (i)(3) Where additional information on the investments may be obtained. 5.8(j) Information on the performance of the Distribution Network Service Provider s network, including 5.8(j)(1) 5.8(j)(2) A summary description of reliability measures and standards in applicable regulatory instruments. A summary description of the quality of supply standards that applies, including the relevant codes, standards and guidelines. Section Section (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 Section (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 Section (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 Section (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 (k) Information on the Distribution 5.8(k)(1) A summary of any asset management strategy employed by the Distribution Network Service Provider. Section 9.1 to 9.3 Network Service Provider s asset Review by: 12/2014 Page 308 of 309

310 management approach, including 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 Section (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 4.2 Section (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 a qualitative summary of 5.8(l)(1) 5.8(l)(2) Non-network options that have been considered in the past year, including generation from embedded generating units. Actions taken to promote non-network proposals in the preceding year, including generation from embedded generating units. Section 7 5.8(l)(3) The Distribution Network Service Provider s plans for demand management and generation from embedded generating units over the forward planning period. 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 (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) 5.8(n)(2) Sub-transmission lines, zone substations and transmission-distribution connection points 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 Section 6.5 Review by: 12/2014 Page 309 of 309