Jemena Electricity Networks (Vic) Ltd 2015 Distribution Annual Planning Report

Transcription

1 Jemena Electricity Networks (Vic) Ltd 2015 Distribution Annual Planning Report Public 24 December 2015

2 An appropriate citation for this paper is: 2015 Distribution Annual Planning Report Contact Person Jason Pollock Senior Network Planning Engineer Ph: Jemena Electricity Networks (Vic) Ltd ABN Level 16, 567 Collins Street Melbourne VIC 3000 Postal Address PO Box Melbourne VIC 3000 Ph: (03) Fax: (03)

3 EXECUTIVE SUMMARY EXECUTIVE SUMMARY Jemena is the licensed electricity distributor for the north-west area of greater metropolitan Melbourne. The Jemena electricity network supplies electricity to more than 320,000 customers throughout a 950 square kilometre area. It supplies a mix of major industrial areas, residential growth areas, established inner suburbs, some major transport routes, and the Melbourne International Airport, which is located at the approximate physical centre of the network. The network service area ranges from Gisborne South, Clarkefield and Mickleham in the north to Williamstown and Footscray in the south and from Hillside, Sydenham and Brooklyn in the west to Yallambie and Heidelberg in the east. The 2015 Distribution Annual Planning Report (DAPR) details the past performance of Jemena s electricity network, summarises the asset management, demand forecasting and network development methodologies adopted by Jemena, and presents forecast electricity demand for the forward planning period (five year planning period from 2016 to 2020). The report also identifies existing and emerging network limitations to supplying forecast demand, and identifies and proposes credible options to alleviate or manage the identified electricity network limitations. Demand growth As a whole, the growth in demand across Jemena s electricity network is slowing, with the network-wide 50% probability of exceedence (POE) summer maximum demand forecast to grow at an average rate of just 1.05% per annum between 2016 and 2021, compared to a historical average growth rate of 2.44% per annum over the past nine years. Figure 1 shows the historical observed demand and ten-year forecasts for summer and winter, 10% POE and 50% POE conditions. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd iii

4 EXECUTIVE SUMMARY Figure 1: Jemena historical and total maximum demand Despite the general slowing in demand growth at the network level, there are areas within the network where maximum demand is forecast to grow well beyond the network average level, while other parts of the network are forecast to experience a decline in maximum demand as a result of manufacturing closures, such as Ford s manufacturing plant in Broadmeadows. In general, demand growth is predominately expected in the north of the network, and this is largely due to new developments associated with urban sprawl toward the edge of the urban growth zone. As a result of this urban sprawl and the recent rezoning of the Urban Growth Boundary, we expect to see continued strong growth in the areas currently supplied by zone substations at Kalkallo (maximum demand forecast to grow at an average of 8.8% per annum over the next six years), Somerton (4.0%), Sunbury (3.0%), Sydenham (2.1%), and Coolaroo (1.9%). Some pockets within more established areas of the network are also experiencing strong growth as a result of amendments to high density living planning schemes. The high growth is predominately due to development of high rise residential and office buildings, and the expansion of community facilities and services, such as around the Footscray Central Activity District, Essendon Airport and Melbourne International Airport. As a result, we are forecasting high growth in maximum demand for areas currently supplied by zone substations at Tullamarine (maximum demand forecast to grow at an average of 5.5% per annum over the next six years), Fairfield (2.8%), Footscray East (2.3%), Airport West (2.1%), and Coburg South (1.7%). In other parts of the network, generally to the south, we are expecting low growth or a decline in maximum demand over the forward planning period. Table 1 presents a summary of the expected growth/decline in maximum demand across Jemena s electricity network over the next six years. iv Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

5 EXECUTIVE SUMMARY Table 1: Supply area average annual maximum demand growth rate ( ) Supply area average annual growth ( ) Season Strong growth (>5% p.a) High growth (3-5% p.a) Medium growth (1-3 % p.a) Low growth and decline (<1% p.a) Summer Kalkallo, Tullamarine, Watsonia Somerton, Sunbury Airport West, Coburg South, Coolaroo, Fairfield, Flemington, Footscray East, Sydenham, Yarraville Braybrook, Broadmeadows, Broadmeadows South, Coburg North, East Preston, Essendon, North Essendon, Footscray West, Heidelberg, North Heidelberg, Newport, Pascoe Vale, Preston, St Albans, Thomastown, Tottenham Network augmentation Due to varying (and non-coincidental) maximum demand growth across the Jemena electricity network, the utilisation forecasts for a number of assets justify network augmentation. As a result, and to maintain asset utilisation at levels that support the efficient and reliable delivery of electricity to our customers, Jemena is proposing to undertake the following key network developments within the next five years: Redevelopment of the Flemington Zone Substation by November Redevelopment of the Sunbury Zone Substation by November Establishment of a new zone substation at Craigieburn (CBN) by November Asset replacement In addition to planning network augmentations to ensure sufficient network capacity to supply customers, Jemena is responsible for managing its existing assets to ensure ongoing safety and reliability of supply. Utilising asset condition monitoring techniques, Jemena has identified that the following assets are near the end of their useful life and pose increased public safety and reliability risks justifying their replacement within the next five years: Replacement of the Airport West Zone Substation relays, with establishment of a new control building, by November Replacement of the three North Essendon Zone Substation transformers with 12/18 MVA 22/11 kv units by November Replacement of Broadmeadows Zone Substation relays by November Establishing a new 66/22 kv Preston Zone Substation (PTN) by November Replacement of the three Fairfield Zone Substation transformers with 12/18 MVA 22/ kv dual secondary winding units by November Replacement of the two Essendon Zone Substation transformers with 20/33 MVA units by November Replacement of the North Heidelberg Zone Substation relays by November Replacement of Footscray East Zone Substation switchgear by November Replacement of the two Heidelberg Zone Substation transformers with 20/33 MVA 66/11 kv units by November Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd v

6 EXECUTIVE SUMMARY Replacement of Coburg North Zone Substation relays, with establishment of a new control building, by November Replacement of Footscray West Zone Substation relays and 22 kv switchgear by November vi Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

7 TABLE OF CONTENTS TABLE OF CONTENTS Executive Summary... iii Glossary... viii Station Names... xii Abbreviations... xiv 1. Introduction and Network Overview Purpose of the DAPR Jemena Electricity Network Changes since the 2014 DAPR Network Development Process and Drivers Annual Planning Review Process Asset Management Approach Demand Forecasting Methodology Network Planning Methodology Network Performance Network Performance Indicators Historical Network Performance Network Performance Targets Network Performance Corrective Action Quality of Supply Power Quality Corrective Action Network Demand Forecasts Changes to Demand Forecasts Forecast Demand Network Development Network Development Overview Summary of RIT-D Applications Metering and Information Technology Systems Demand Management Factors that may Materially Impact the Network Zone Substation and Feeder Line Limitations Sub-transmission Line Limitations Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd vii

8 GLOSSARY GLOSSARY Advanced Metering Infrastructure (AMI) meter capital expenditure (CAPEX) CIGRE condition based risk management (CBRM) constraint contingency condition (or event) contingency probability degree of polymerisation (DP) value deterministic method dielectric dissipation factor (DDF) discounted cash flow (DCF) (analysis) energy-at-risk expected unserved energy (EUSE) Jemena Electricity Network (JEN) limitation load duration curve Also referred to as a smart meter, AMI meter is an electronic device that, among other functions, records electricity consumption at hourly (or less) intervals and communicates that information to a utility for monitoring and billing. Expenditure to buy fixed assets or to add to the value of existing fixed assets to create future benefits. The International Council on Large Electrical Systems Refers to a management process that utilises current network asset condition information, engineering knowledge and practical experience to predict future asset condition, to calculate the risks of asset failures in order to guide investment decisions. Refers to a constraint on network power transfers that affects customer service. Refers to the loss or failure of part of the network. An event affecting the power system that is likely to involve the failure or removal from operational service of one or more generating units and/or network elements. The probability that a contingency condition (or event) will occur, and typically approximated by multiplying the number of times a contingency condition occurs (usually in a year) by its duration, normalised by the total available time (in this case, a year). Refers to the value established from diagnostic testing and historical data that indicates the condition of paper insulation within the transformer, and is an important parameter in its end-of-life assessment. A simplified planning methodology that does not explicitly take into account outage or environment condition probability to guide investment. A measure of the dielectric losses in an electrical insulating liquid. A valuation method that estimates the attractiveness of an investment opportunity. Discounted cash flow (DCF) analysis uses future free cash flow projections and discounts them (often using the weighted average cost of capital) to arrive at a present value, which is used to evaluate the investment potential. The total energy at risk of not being supplied if a contingency occurs. Refers to an estimate of the long-term, probability weighted, average annual energy demanded (by customers) but not supplied. The EUSE measure is transformed into an economic value, suitable for cost-benefit analysis, using the value of customer reliability (VCR), which reflects the economic cost per unit of unserved energy. One of five licensed electricity distribution networks in Victoria, JEN is 100% owned by Jemena and services more than 320,000 customers within a 950 square kilometre distribution system covering the north-west area of greater Melbourne. Refers to a limitation on a network asset s capacity to transfer power. Shows the amount of time (usually over a year) that demand was within a given percentage of the maximum demand (MD). viii Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

9 GLOSSARY maximum demand (MD) maximum demand scenario megavolt ampere (MVA) Momentary Average Interruption Frequency Index (MAIFI) national meter identifier (NMI) network network augmentation network capacity neutral earthing resistor (NER) non-network non-network alternative on-load tap-changer (OLTC) The highest amount of electrical power delivered (or forecast to be delivered) for a particular season (summer and/or winter) or the year. Refers to the possible (projected) maximum demand resulting from a given level of population and economic growth. Scenarios usually examine the possible maximum demand outcomes resulting from high, medium and low growth, with a medium growth scenario often expected to be the most likely. Refers to a unit of measurement for the apparent power in an electrical circuit. Also million volt-amperes. A reliability index commonly used by electricity utilities, MAIFI is the average number of momentary interruptions that a customer will experience during a given period (typically a year). A momentary interruption is defined as an outage of less than one minute in duration. A unique number used to identify a meter (the electricity connection point) measuring electricity consumption. Refers to the physical assets required to transfer electricity to customers. An investment that increases network capacity to prudently and efficiently manage customer service levels and power quality requirements. Augmentation usually results from growing customer demand. Refers to the network s ability to transfer electricity to customers. A device designed to reduce ground fault current levels. NERs consist of resistor elements connected in a series or parallel arrangement. NERs have no moving parts and are considered to be reliable. Refers to anything potentially affecting the transfer of electricity to customers that does not involve the network. A response to growing customer demand that does not involve network augmentation. A connection point selection mechanism that enables stepped voltage regulation without interrupting supply, OLTCs: Change the ratio of the primary to secondary windings by physically adding or subtracting windings from the primary or secondary whilst the transformer is on load. Are an integral power transformer component. operating expenditure (OPEX) oil temperature indicator (OTI) peak demand planning criteria polarisation and depolarisation current (PDC) polychlorinated biphenyls (PCBs) Expenditure (ongoing) for running a product, business or system. An indicator of oil temperatures within a transformer. The highest amount of electrical power delivered (or forecast to be delivered) during a morning, afternoon, evening, day, week, and/or month. The methodologies, inputs and assumptions that must be followed when undertaking technical and economic analysis to predict emerging power transfer limitations. A measurement of a transformer insulation system s dielectric response. See also recovery voltage measurement (RVM). An electrical insulating liquid that is no longer used due to its carcinogenic property. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd ix

10 GLOSSARY power quality power transformer probabilistic method probability of exceedence (POE) recovery voltage measurement (RVM) Regulatory Investment Test for Distribution (RIT-D) Regulatory Investment Test for Transmission (RIT-T) reserve feeder (service) SAP service target performance incentive scheme (STPIS) substation service isolating transformer substation service transformer System Average Interruption Duration Index (SAIDI) System Average Interruption Frequency Index (SAIFI) system normal Refers to the fitness of electrical power for the consumer devices it is required to supply. The Victorian Distribution Code (VDC) and National Electricity Rules (NER) set the power quality obligations for Jemena Electricity Network s (JEN) network operations. Refers to a power transformer installed in a zone substation and includes any associated ancillary equipment. Power transformers in the JEN system transform a sub transmission voltage into a distribution voltage. A planning methodology applied to network types with the most significant constraints and associated augmentation costs. It involves estimating the cost of a network limitation with consideration of the likelihood and severity of network outages and operating conditions. Refers to the probability, as a percentage, that a forecast will be met or exceeded (for example, due to weather conditions) for a particular period of time. A measurement of a transformer insulation system s dielectric response. See also polarisation and depolarisation current (PDC). A test administered by the Australian Energy Regulator (AER) that establishes consistent, clear and efficient planning processes for distribution network investments in the National Electricity Market (NEM). A test administered by the Australian Energy Regulator (AER) that establishes consistent, clear and efficient planning processes for transmission network investments in the National Electricity Market (NEM). A service ensuring continuity of supply if the normal feeder supply to a customer s connection is interrupted. Reserve feeder capacity comes from an alternative feeder with the capacity to meet the customer s requirements. SAP is a software application used within Jemena to support a number of functions including procurement and logistics, works and asset management, customer management, resource management and operation analytics. A scheme administered by the Australian Energy Regulator (AER) designed to provide incentives for each distribution network service provider (DNSP) to maintain or improve service reliability. Refers to a substation service transformer that is supplied from the low-voltage (LV) network. See also substation service transformer. Refers to a transformer that provides auxiliary power supplies for battery chargers, OLTC controls, general light, and power inside an electricity zone substation. Substation service transformers can be supplied from the high voltage (HV) or low voltage (LV) network (where they are referred to as substation service isolating transformers). A reliability index commonly used by electricity utilities, SAIDI is the average outage duration experienced by customers served, and is measured in units of time (often minutes or hours). A reliability index commonly used by electricity utilities, SAIFI is the average number of interruptions experienced by a customer, measured in units of interruptions per customer. The condition where no network assets are under maintenance or forced outage, and the network is operating according to normal daily network operation practices. x Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

11 GLOSSARY value of customer reliability (VCR) zone substation Represents the dollar value customers place on a reliable electricity supply (and can also indicate customer willingness to pay for not having supply interrupted). Refers to the location of transformers, ancillary equipment and other supporting infrastructure that facilitate the electrical supply to a particular zone in the Jemena Electricity Network (JEN). Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd xi

12 STATION NAMES STATION NAMES ACI APF AW BD Australian Glass Manufacturers Zone Substation Australian Paper Fairfield Zone Substation (decommissioned) Airport West Zone Substation Broadmeadows Zone Substation BMS Broadmeadows South Zone Substation (commissioned in 2015) BK BLTS BTS BY CBN CN COO CS EP-A EP-B Brunswick Zone Substation Brooklyn Terminal Station Brunswick Terminal Station Braybrook Zone Substation Craigieburn Zone Substation (proposed) Coburg North Zone Substation Coolaroo Zone Substation Coburg South Zone Substation East Preston Zone Substation Switch House A East Preston Zone Substation Switch House B EPN East Preston Zone Substation (66/22 kv, commissioned in 2015) ES FE FF FT FW GSB HB KLO KTS L MAT MB MLN NEI NH NS NT P Essendon Zone Substation Footscray East Zone Substation Fairfield Zone Substation Flemington Zone Substation Footscray West Zone Substation Gisborne Zone Substation Heidelberg Zone Substation Kalkallo Zone Substation Keilor Terminal Station Deepdene Zone Substation Melbourne Airport Zone Substation Melbourne Water Zone Substation Melton Zone Substation Nilsen Electrical Industries Zone Substation North Heidelberg Zone Substation North Essendon Zone Substation Newport Zone Substation Preston Zone Substation xii Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

13 STATION NAMES PTN PV Q SA SBY SHM SMTS SPS SSS ST TH Preston Zone Substation (proposed 22 kv) Pascoe Vale Zone Substation Kew Zone Substation St Albans Zone Substation Sunbury Zone Substation Sydenham Zone Substation South Morang Terminal Station Somerton Power Station Somerton Switching Station Somerton Zone Substation Tottenham Zone Substation TMA Tullamarine Zone Substation (commissioned in 2015) TSTS TT TTS VCO WMTS WND WT YVE Templestowe Terminal Station Thomastown Zone Substation Thomastown Terminal Station VisyPaper Zone Substation West Melbourne Terminal Station Woodend Zone Substation Watsonia Zone Substation Yarraville Zone Substation Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd xiii

14 ABBREVIATIONS ABBREVIATIONS AAC ABC ACR ACSR AEMC AEMO AER AMI AS/NZS AVR CAPEX CBRM CC CCA CCT CMEN DAPR DB DC DM DMS DNSP DP DSPR DUoS EDC EDPR EMF ENA EPA ESELC ESMP ESMS All Aluminium Conductor Aerial Bundled Conductor Automatic Circuit Recloser Aluminium Conductor Steel Reinforced Australian Energy Market Commission Australian Energy Market Operator Australian Energy Regulator Advanced Metering Infrastructure Australian Standard/New Zealand Standard Automatic Voltage Regulators capital expenditure condition based risk management Covered Conductors Copper Chrome Arsenate Circuit Common Multiple Earthed Neutral Distribution Annual Planning Report Distribution Business Direct Current Demand Management Distribution Management System Distribution Network Service Provider Degree of Polymerisation Distribution System Planning Report Distribution Use of System (charges) Victorian Electricity Distribution Code Electricity Distribution Price Review Energy at Risk Electromagnetic Field Energy Networks Association Environment Protection Authority Electricity Safety (Electric Line Clearance) Regulations Electricity Safety Management Plans Electricity Safety Management Schemes xiv Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

15 ABBREVIATIONS ESV EUSE GWh HSEQ HV ISO IS JEN ka kv LCMP LV MAIFI MVA MVAR MW NER NIEIR OFAF OLTC ONAF ONAN OOS OPEX PAS PCB PQ PSSE P.U RIT-D RIT-T RTU SAIDI SAIFI SCADA SF6 Energy Safe Victoria Expected Unserved Energy Gigawatt hour Health, Safety, Environment and Quality High-voltage International Organization for Standardization Information Services Jemena Electricity Networks (Vic) Ltd kilo Amps kilo Volts Life Cycle Management Plan Low-voltage Momentary Average Interruption Frequency Index Mega Volt Ampere Mega Volt Ampere Reactive Mega Watt National Electricity Rules National Institute of Economics and Industry Research Oil Forced/Air Forced On Load Tap Changer Oil Natural/Air Forced Oil Natural/Air Natural Out of service Operating expenditure Publicly Available Specification Polychlorinated biphenyl Power Quality Power System Simulator for Engineering Per unit Regulatory Investment Test Distribution Regulatory Investment Test Transmission Remote Telemetry Units System Average Interruption Duration Index System Average Interruption Frequency Index Supervisory, Control and Data Acquisition Sulphur Hexafluoride Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd xv

16 ABBREVIATIONS STPIS SUPS SWER TEV URD USE VCR VEDN VESI XLPE Service Target Performance Incentive Scheme Substation utilisation and profiling Single wire earth return Transient earth voltages Underground residential development Unserved energy Value of customer reliability Victorian Electricity Distribution Networks Victorian Electricity Supply Industry Cross-linked polyethylene xvi Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

17 INTRODUCTION AND NETWORK OVERVIEW 1 1. INTRODUCTION AND NETWORK OVERVIEW 1.1 PURPOSE OF THE DAPR This 2015 Distribution Annual Planning Report (DAPR) has been prepared by Jemena as the Distribution Network Service Provider (DNSP) for the north-west area of greater metropolitan Melbourne, and in accordance with the requirements set out in Clause 5.13 of the National Electricity Rules (NER). The DAPR, which includes an overview of our network and operating environment, presents a proposed network development plan to economically manage the network and network limitations identified within the forward planning period (the five-year planning period from 2016 to 2020). The DAPR also summarises: The annual planning review of our electricity distribution network. Past performance as well as information about existing and forecast distribution network limitations. Our asset management system, and forecasting and network planning methodologies used to identify network limitations and assess credible options to manage or alleviate those limitations. The DAPR is the key mechanism for communicating identified network limitations to industry and interested parties, and forms an essential part of the network development consultation process. Assessments are conducted at a high level to identify and indicate the relative magnitude of network limitations, without conducting a detailed, network development strategy, level of assessment. Interested parties, particularly potential non-network support providers, are encouraged to use the DAPR as a platform for discussing alternative options that may help manage network loading and ensure ongoing reliable and cost-efficient electricity supply to Jemena s customers. 1.2 JEMENA ELECTRICITY NETWORK Jemena is the licensed electricity distributor for the north-west area of greater metropolitan Melbourne. The Jemena electricity network supplies electricity to more than 320,000 customers across a 950 square kilometre area. It supplies a mix of major industrial areas, residential growth areas, established inner suburbs, some major transport routes, and the Melbourne International Airport, which is located at the approximate geographical centre of the network. Figure 1 1 shows the Jemena electricity network supply area, which ranges from Gisborne South, Clarkefield and Mickleham in the north to Williamstown and Footscray in the south, and from Hillside, Sydenham and Brooklyn in the west to Yallambie and Heidelberg in the east. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 1

18 1 INTRODUCTION AND NETWORK OVERVIEW Figure 1 1: Jemena electricity network supply area Table 1 1 presents a summary of the network s key characteristics. Table 1 1: Network summary at December 2015 Network characteristic Supply area (location) Characteristic detail North-west metropolitan Melbourne Supply area (square kilometre) 950 Line length (km) Sub-transmission lines (number and voltage) 6,159 (4,440 overhead and 1,719 underground) 46 (66 kv and 22 kv) Feeder lines (number) 227 Electricity poles (number) 101,915 Transmission connection points (location) Brunswick, Brooklyn, Keilor, South Morang, Templestowe, Thomastown, West Melbourne Zone substations (number) 26 Zone substations combined capacity (MVA) 1,770 Distribution substations (number) 6,360 2 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

19 INTRODUCTION AND NETWORK OVERVIEW OPERATING ENVIRONMENT Jemena operates in an environment that is impacted by its network characteristics, ownership and control, stakeholders, regulatory objectives and expenditure drivers. The key environmental factors impacting on asset management include: Changing customer preferences associated with the supply of electricity. Aging assets presenting technical risks. Significant regulatory compliance obligations. Changes to the physical environment in which the assets are located. Assets located in areas of high bushfire risk. Assets capable of having adverse impacts on the environment. The changing nature of the key services provided by network assets with increasing embedded generation connections, and the installation of smart metering devices. The operating environment in which Jemena s electricity network exists is changing. Rising network fault levels due to capacity expansion and the connection of embedded generators are resulting in increasing stress on parts of the network. Changing regulatory obligations are impacting safety and compliance work plans, and growing customer expectations are creating new challenges for providing reliable, cost efficient and environmentally responsible energy delivery. Jemena recognises that its network is aging and that, because of the operating environment changes, assets that were operating satisfactorily in the past may no longer meet safety, compliance or service performance requirements in the future. In response, Jemena has a strategy to continually review its asset management strategies to ensure that assets continue to perform at a level that meets stakeholder requirements. Jemena also continues to focus on maintaining its service performance, whilst evaluating initiatives to adapt to a changing environment, including: Improving network resilience to wind and extreme heat events. Implementing changes to bushfire management. Improving management of extreme weather events. Responding to government energy policy initiatives. Developing and applying smart network technologies. Developing options and flexibility for our network and customers through the application of demand management solutions. Leveraging the advanced metering infrastructure as a catalyst for improvements. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 3

20 1 INTRODUCTION AND NETWORK OVERVIEW 1.3 CHANGES SINCE THE 2014 DAPR Table 1 2 lists the information provided in this 2015 DAPR which has been added or significantly updated from the 2014 DAPR. Table 1 2: Changes to 2015 DAPR Description Jemena s quality of supply obligation, as outlined in the Electricity Distribution Code (EDC) and National Electricity Rules (NER), and quality of supply performance for the 2014/15 period. Section 3.5 Joint planning conducted between Jemena and relevant Network Service Providers (NSPs) and Additional details on Jemena s energy and demand forecasting process, including background input assumptions. 2.3 How Jemena treats losses in its planning processes Methods used by Jemena to forecast network performance Jemena s 2014/15 investments in metering and information technology systems, and planned investments in the forward planning period. 5.3 Additional details on Jemena s demand side management policy and strategy. 5.4 Discussion on factors which have a material impact on Jemena s network capability Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

21 NETWORK DEVELOPMENT PROCESS AND DRIVERS 2 2. NETWORK DEVELOPMENT PROCESS AND DRIVERS This section provides an overview of Jemena s network development process, including a summary of the annual planning review process and asset management system. It also provides a summary of the demand forecasting methodology and network planning methodologies used to identify, assess and address network limitations. 2.1 ANNUAL PLANNING REVIEW PROCESS The Distribution Annual Planning Report (DAPR) forms part of the annual planning process undertaken by Jemena, and is a summary of the annual electricity distribution network planning review. The review process includes an assessment of supply limitations and risks on the sub-transmission lines, zone substations and high-voltage feeder lines. It also identifies and proposes feasible options for managing or mitigating identified network limitations. Network planning is a continuous process with key activities including: Monitoring and reviewing asset and network performance. Preparing load demand forecasts. Identifying network limitations. Identifying feasible options to manage or mitigate network limitations. Identifying and proposing the most feasible option to maximise the net economic (i.e. customer) benefits. Figure 2 1 provides a high level flow chart of the annual planning review process. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 5

22 2 NETWORK DEVELOPMENT PROCESS AND DRIVERS Figure 2 1: Annual planning review process flow chart AEMO Plant ratings and network capacity Load data forecast Regulatory Documents Service Standards Condition Monitoring Asset Management Model network loading and performance. Identify system inadequacies and constraints and evaluate risks and options. Identify feasible network options. Estimate costs and lead times. Prepare five-year capital expenditure plan (EDPR submission) Publish Distribution Annual Planning Report Proponents of non-network solutions respond to Distribution Annual Planning Report Detailed economic and technical evaluation of feasible options (Including RIT-D assessment as appropriate) Select preferred options Review compliance with Licence and Regulatory requirements Management / Board Approval of Projects approval Implementation of projects 6 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

23 NETWORK DEVELOPMENT PROCESS AND DRIVERS TRANSMISSION NETWORK JOINT PLANNING Joint planning with Victoria s Transmission Network Service Provider (TNSP) and jurisdictional planning authority (AEMO) is conducted in accordance with Clause of the NER and Clause 3.4 of the Victorian Electricity Distribution Code (EDC). A key outcome of this joint planning is the preparation of the Transmission Connection Planning Report (TCPR), which is prepared in collaboration with the four other distribution network service providers (DNSPs) in Victoria 1. The TCPR assesses supply limitations and identifies proposed augmentations for assets that connect the Victorian transmission network to DNSP networks, such as the 220/66 kv and 220/22 kv transformers. Although the DNSPs undertake connection asset capacity planning, the assets are owned and managed by Victoria s TNSP, AusNet Services (Transmission). Demand and energy forecasts for Jemena s connection points can be found in the 2015 TCPR 2. A Memorandum of Understanding (MoU), agreed between AEMO the five Victorian electricity Distribution Businesses (DBs), sets out a framework for cooperation and liaison between AEMO and the DBs with regard to the joint planning of the shared network and connection assets in Victoria. It also sets out the approach to be applied by AEMO and the DBs 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 assets. Where connection asset capacity planning requires significant development of existing, or establishment of new, terminal station assets, AEMO will be involved in the joint planning process. Where connection assets are shared between DBs, the DB with the majority of its demand supplied by the affected asset will typically lead the planning assessment DISTRIBUTION NETWORK JOINT PLANNING Joint planning with surrounding DNSPs is conducted in accordance with Clause of the NER. Table 2 1 below summaries shared sub-transmission assets for which Jemena conducts joint planning with other DNSPs. Table 2 1: Shared DNSP asset planning 66 kv sub-transmission loop Shared asset owner 2015 DAPR section addressing planning outcome KTS-MLN-SBY (WND-GSB)-SHM Powercor TSTS-HB-L-Q CitiPower TTS-NEI-NH-WT AusNet Jemena and the neighbouring DB will share demand forecasts, and the relevant DB who owns the asset will conduct the assessment in accordance with the planning obligations (see section 2.4.1). For example, planning of the TTS-HB-L-Q sub-transmission loop requires both Jemena and CitiPower to share demand forecasts for their respective substations because the TSTS-HB 66 kv line is owned by Jemena, whereas the TSTS-L 66 kv line is owned by CitiPower. 1 2 The five Victorian DNSPs are: Jemena, CitiPower, Powercor Australia, United Energy, and AusNet Services (Distribution). Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 7

24 2 NETWORK DEVELOPMENT PROCESS AND DRIVERS 2.2 ASSET MANAGEMENT APPROACH Jemena is committed to employing best industry asset management practice to prudently manage our assets over their total life cycle. We recognise the importance of sound asset management in ensuring the efficient delivery of services that meet customer and stakeholder requirements. Network design, construction, maintenance, operations, asset investment and innovation are vital components of asset management, with effective asset management having a direct impact on customer service, electricity pricing, safety and shareholder value. Jemena undertakes these activities in accordance with its asset management framework ASSET MANAGEMENT FRAMEWORK Jemena s asset management framework governs the process of establishing work programs focussed on safety, people, performance, our customers and growth, and includes a series of documented policies and objectives comprising the: Asset Management Policy This policy statement describes Jemena s intentions and the principals for asset management as they are applied throughout the business; Asset Management Strategy and Objectives (AMSO) The AMSO aims to: Identify the electricity network and asset management strategies and objectives based on the overarching business drivers and Jemena s business plan and compliance requirements. Provide governance within the business by providing relevant plans with strategic direction. Inform key stakeholders about Jemena s asset management strategy and to facilitate the development of the asset class strategies, network development strategies, the 5-Year Asset Management Plan (AMP) and the Capital and Operational Work Plan (COWP). Asset Management Plan (AMP) The AMP comprises: The 20-Year Strategic Asset Management Plan (SAMP), which informs the long term operational and asset management trends, long term customer preferences, and the influence of new technology and policy changes on the business operations. The 5-Year AMP, which provides a medium term outlook of operational environment, asset conditions and asset investment plans. The COWP, which provides the two-year plan of activities to be performed by Jemena in designing, constructing, operating, maintaining and supporting Jemena s electricity distribution network. Figure 2 2 shows the inputs and outputs of Jemena s asset management framework, which represents an integrated approach to aligning our corporate objectives with individual asset management objectives. The asset management framework incorporates the asset management system s scope and boundaries in terms of Jemena s policies, strategies, objectives and plans, all of which ensure the appropriateness of our asset management activities. 8 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

25 NETWORK DEVELOPMENT PROCESS AND DRIVERS 2 Figure 2 2: Jemena asset management framework Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 9

26 2 NETWORK DEVELOPMENT PROCESS AND DRIVERS ASSET MANAGEMENT DRIVERS Jemena has identified a series of strategic asset management drivers. Along with specific asset class drivers, these drivers are used as the basis for developing asset management strategies, and include: Health, safety and environment. Stakeholder expectations. Growth, demand and customer connections. Supply reliability and quality. Regulatory compliance (including technical, safety and the environment). Technology. Combined, these strategic asset management drivers help us to balance the individual asset class drivers with an overall network view, so we can optimise the outcomes from the strategies. This is important because today s decisions will affect asset condition, cost and performance over the life of the assets, and thereby affect our ability to provide the safety, service level and cost/price outcomes that our customers expect us to deliver. The following sections provide a summary of the asset management drivers. Health, safety and environment Safety is a number one priority for Jemena. Jemena s policy directives include: Manage our assets without compromising our employees, contractors and the public s safety, as per the Jemena Health and Safety Policy. Apply the Jemena risk management approach to asset management activities. Facilitate continual improvement in the safety and performance of the assets, through the establishment, maintenance and governance of effective asset and safety management systems. All asset lifecycle activities are designed to ensure compliance to health and safety standards and legislation, as well as our own internal controls. Stakeholder expectations Stakeholders are defined as our customers, shareholders, network users, the industry regulators, government departments, and the broader community. We consider and balance the competing interests and preferences of stakeholders including: End users of the electricity we distribute, including households and small, medium and large businesses. Stakeholders and groups who represent our end-user customers, including various consumer advocacy groups and business associations. Technical and economic regulators. Local governments, who are customers of our public lighting services. Energy retailers, who collect revenue from small customers on our behalf. The community expects environmental responsibility; a safe and reliable level of service; a responsive service; public amenity; equitable levels of service available to all consumers; and affordable pricing. 10 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

27 NETWORK DEVELOPMENT PROCESS AND DRIVERS 2 Understanding our customers long-term preferences is critical to us in providing the services that our customers expect. We must also balance this with the interests of other stakeholders, including our regulators (the Australian Energy Regulator, Energy Safe Victoria) and Federal and State Governments. Community expectations drive both our shorter term planning and our longer term planning. Growth, demand and customer connections Growth, demand, and customer connections can be driven by: Customer demand and energy forecasts meeting anticipated maximum demand with acceptable levels of security and reliability of supply is a capacity and demand driver. This may require increases in capacity of the integrated assets. New customer connections, numbers and growth we are obliged to make an offer to connect new customers to the network, ranging from individual properties and urban residential developments through to new large commercial and industrial customers. New and additional supply points (underground and overhead), increased supply, upgrading of low voltage mains, minor low voltage extensions and the installation of low voltage substations. New or upgraded public lighting including both major and minor road schemes, single major and minor lights, watchman lights, and sustainable lights. Capital works carried out for customers (including authorities) where the actual costs are externally financed and for which the prime purpose is to satisfy a requirement other than new or increased supply. This includes customer or developer requests for minor pole relocations together with distribution network rectification work due to third party damage. Embedded generation and demand-side management initiatives this becomes relevant when existing and new installations influence demand levels and technical characteristics across the network in a dynamic and complex manner. Maintaining supply and asset utilisation pre-defined, risk-based planning criteria are used to assess the economic merit of investment compared with the potential for unserved energy. This informs the overall level of asset utilisation, which must be maintained at a level that ensures suitable supply following outages of key assets. Solutions to these may be either demand management (as a solution to reduce energy at risk), or traditional network augmentation. As detailed in Section , applying our risk-based network planning criteria also accounts for the cost of network power losses, and includes the benefits of reducing these losses. Asset integrity Asset integrity covers the provision of the required service standards expected of the particular asset class, and include: Service standards prescribed service levels are mandated through license conditions and regulations. Increasing fault levels, voltage issues, reactive power issues and degradation in power quality may drive network augmentation. Maintaining the asset performance and condition of an increasing and aging asset base supply reliability and quality is dictated by how the assets perform their intended functions. Failures can directly lead to customer interruptions. New failure modes for assets As assets age and are subject to environmental conditions, new failure modes can arise that must be managed based on the safety and reliability risks involved. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 11

28 2 NETWORK DEVELOPMENT PROCESS AND DRIVERS Service target performance incentive scheme (STPIS) provides a mechanism for the AER to financially reward or penalise network businesses based on service performance. Annual targets are based on the previous year s performance. Maintaining asset integrity through a combination of asset performance, risk and operational safety a network failure, due to a loss of asset integrity can cause personal injury or loss of life, property and environmental damages and loss of supply. Our asset management needs to comply with corporate and legislative requirements. This is linked closely to, and overlaps with our health, safety and environment driver. Regulatory compliance Aspects of compliance that are asset management drivers include: Mandated compliance and safety obligations Various standards relating to matters such as security and safety impact on both the design of existing and new plant and operational expenditure activities. Bushfire mitigation and vegetation management. Environmental obligations this involves greenhouse gas emissions, noise, contaminants, vegetation, and bushfires. Emergency response capability We will continue to ensure safe and efficient operations in the future by complying with corporate and legislative requirements, as well as implementing prudent and industry best practice measures so as to meet customers long term interests. Technology Changes in technology and network capability can be a driver for changes in how we manage the network. Technology drivers include, but are not limited to: Demand side technology: Demand management technologies and innovation (storage, AMI, distributed generation, customer side innovation). Customers want us to explore new ways of more efficiently delivering our services and enabling them to use our services more efficiently. This involves leveraging new AMI technology to better empower customers to more efficiently use electricity and also incentivise behavioural usage change to reduce traditional poles and wires expenditure, and focus more on smart technology use. Supply side technology: Network monitoring and control. Information technology-based systems for network operations, engineering and capital works, customer management, retailer management, billing, and corporate services. In addition to these, changes in technology may drive change in how we manage the asset to ensure efficiency in the provision of our services and ensuring that our expenditure is in the long term interests of customers. Risk management All of the preceding drivers are assessed through a structured risk management program that is essential to minimise reasonably foreseeable disruption to operations, harm to people and damage to the environment and property. All our risk management activities are governed by the Jemena s risk management policy and 12 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

29 NETWORK DEVELOPMENT PROCESS AND DRIVERS 2 framework. This framework enables us to identify, evaluate and appropriately manage credible risks to be as low as reasonably practicable, and minimise the costs of doing so. Our long-term asset management decisions will be prudent from the perspective of both customers and investors, and will reflect the way the regulatory framework supports and provides certainty to our investors in terms of recovering their capital investments. Certainty is primarily provided by the AER s regulatory framework, which provides reasonable opportunities to recover network investments as well as ensuring efficient long-term investment decisions. This has become even more important as energy sources have become commercialised and increasingly affordable and accessible ASSET MANAGEMENT STRATEGIES AND OBJECTIVES Jemena s asset management strategies and objectives are developed to maintain the existing service levels, which our stakeholders have indicated is their preference, and to ensure: Alignment with our business plan and asset management policy. Capacity to meet load growth is achieved. The connection of new customers. Management of asset performance, condition and risks (network, asset and public safety). Maintenance of network service levels including customer service, quality of supply and reliability of supply. Network development strategies Jemena produces network development strategies for specific customer supply areas. Each area s network development strategy document provides information about supply capacity and network demand growth impacting the supply capacity in that area. They also provide information about: Specific investment drivers. The assessment methodology and assumptions, including information relating to economic planning, demand forecasts, asset ratings, value of customer reliability (VCR), network outage rates, discount rates, and costs. A summary and analysis of each credible option, including assessments of gross market benefits, net market benefits, and a sensitivity analysis. A proposed option. The network development strategies are developed in accordance with the JEN Network Planning Criteria and the Network Planning Methodology outlined in Section 2.4. The strategic approach in preparing the network development strategies is to provide network capacity to meet load growth, including the connection of new customers. The key drivers that network development strategies typically aim to address are: Growth, demand and customers connections. Stakeholder expectations. Technology. Risk management. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 13

30 2 NETWORK DEVELOPMENT PROCESS AND DRIVERS Asset class strategies Jemena produces individual asset class strategies for each of its asset classes. These documents summarise the optimal lifecycle management plan for each asset class, and consider: The management of existing asset performance, risk and condition. Strategies for asset acquisition and creation, utilisation, maintenance and renewal/disposal. The documents are developed with consideration of the: Asset class profile, which includes information about the type, specifications, life expectancy and age profile of each the asset class in service; Asset strategies, which includes key strategies and plans that support Jemena s business plan, asset management policy, and asset management strategies and objectives, as well as informing expenditure plans and programs of work; Asset risk, which includes information about asset criticality, failure risks, types and consequences; Asset performance, which provides information about performance objectives, drivers and service levels, and the technical and commercial risks associated with the management of the asset; and Asset expenditure assessment, which provides information about the expenditure decision-making processes, how expenditure options are analysed and historical and forecast operating expenditure (OPEX) and capital expenditure (CAPEX). This also includes decisions about whether to renew or dispose of assets that have reached the end of their economic life based on their performance, risks and supply security or service level requirements. The asset class strategies use leading asset management techniques to ensure an appropriate balance of capital and operational expenditure through the consideration of total lifecycle management costs. Jemena s aim is to ensure that the network and assets are managed optimally to the long term benefit of our customers. The strategies for each asset class are based on the best practice approach to the management of assets including: Asset acquisition/creation. Asset utilisation. Asset maintenance. Asset renewal/replacement/disposal. These factors address the historical and forecast operating and capital expenditure (pre-prioritisation) associated with each asset class and the associated operating risks and performance objectives. This approach: establishes the goals, methods and strategies required to achieve the balanced and efficient creation, utilisation, maintenance, and replacement of each network asset; enables the impact of each element of the lifecycle on program costs and outputs to be considered; and ensures an integrated approach to lifecycle management. Jemena produces asset class strategy documents for each asset class. These provide individual lifecycle strategies based on the optimum balance of capital and operation expenditure, and in accordance with our 14 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

31 NETWORK DEVELOPMENT PROCESS AND DRIVERS 2 asset management strategy and objectives document. The outputs of the asset class strategies have been reassessed on an aggregated network basis to ensure that the network delivers our desired requirements. Table 2 2 lists Jemena s asset classes, along with the number of assets in each class. Table 2 2: Jemena assets by asset class Asset Class Population Asset Class Population Poles 101,915 Zone substation transformers 68 Pole top structures 115,627 HV outdoor fuses 5,646 Conductor (kilometres) 4,385 Surge arrestors 7,164 Overhead line switchgear 1,936 Pole type transformers 4,035 Automatic circuit reclosers 130 Non pole type distribution substations Public lighting 70,725 Zone substation Disconnectors LV overhead services 184,846 Underground distribution systems (kilometres) 2, ,779 LV services and terminations 62,092 Zone substation instrument transformers 232 Communication equipment 490 LV pillars and pits 61,315 Zone substation capacitors 37 Zone substation DC systems 84 Zone substation circuit breakers 445 Zone substation protection relays 1,618 Power quality systems ASSET CRITICALITY, PERFORMANCE AND RISKS Jemena assesses the consequence of failure for each asset class, and selects an appropriate lifecycle management strategy for that asset class. The asset criticality determines the level of analysis required to formulate each asset class strategy, based on a balance of the risk, performance, and costs associated with the asset. Table 2 3 shows that, for most of our asset classes, condition assessment is our primary asset replacement strategy. In some circumstances we will allow assets to fail. This is typically the case for non-critical or consumable devices such as LV fuses or assets where condition monitoring is difficult or disproportionally expensive to implement, such as for underground cables. Age based replacement is not used as a primary replacement strategy, other than for non-major road public lighting lamps, which are replaced every four years. Some assets may exhibit premature failure due to onset of common defects (such as technology or design related issue). In this case we typically implement accelerated programs to replace these assets. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 15

32 2 NETWORK DEVELOPMENT PROCESS AND DRIVERS Run to failure based replacement In this strategy, assets are deliberately allowed to operate until they break down, at which point reactive maintenance or replacement is performed. Age-based replacement While actual asset replacement decisions may include a condition assessment, forecast volumes for planning and regulatory approval purposes may be based on an age or failure rate assessment only. In practice, age based replacement is not utilised other than for non-major road lamps, which are replaced every four years to ensure sufficient lumens are emitted according to Public Lighting Code Clause 2.3.1(c). Condition-based risk management Condition-based risk management (CBRM) is a structured process that combines asset information, engineering knowledge and practical experience to define future condition, performance and risk for network assets. We use our CBRM model to support the condition, age, and failure rate assessment methodologies. Condition monitoring can be invasive, non-invasive or a combination of both. Non-invasive assessment includes activities such as inspections, infra-red surveys and limited testing procedures. Invasive assessment includes activities such as oil sampling and equipment overhauls. Invasive assessment is usually associated with a greater range of inspections and testing procedures. Currently, a CBRM model is being applied to ten of the primary plant assets (nine asset classes). Jemena uses CBRM to identify poor performing assets that will affect the service delivered to our customers. Critical CBRM inputs include: the asset owner s engineering knowledge and practical experience of the assets; asset specification, history (faults, failures, generic experience, maintenance records), duty, environment, test and inspection results; an understanding of degradation and failure modes; and experience of building CBRM models. CBRM outputs include: condition, which provides health indices, health index profiles, probability of failure (POF) and failure rates, and estimates of future failure rates with different interventions; and risk, which provides quantification of the current and future risk for asset groups with different interventions (expressed as a monetary value), criticality involving changed priorities within an asset group, and comparison/optimisation across asset groups. Condition evaluation is applied within the CBRM models to identify the optimum replacement strategy and estimate any future movement in risk for a given replacement strategy. These models are also used to verify that our plans are maintaining reliability, security and safety, rather than improving or degrading them. Table 2 3 summarises the asset lifecycle strategy adopted for each asset class. 16 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

33 NETWORK DEVELOPMENT PROCESS AND DRIVERS 2 Table 2 3: Asset lifecycle strategy for each asset class Asset Condition Assessment Run To Failure Age Based Poles (1) Pole Tops (1) Conductors & Connectors (1) Overhead Line Switchgear (2) Automatic Circuit Reclosers (ACR) (1) Public Lighting (3) (4) HV Outdoor Fuses Surge Arrestors Pole Type Transformers (1) Non Pole Type Distribution Substations (1) Earthing Systems Underground Distribution Systems LV Services Communications Network Devices Metallic Supervisory Cables and Fibre Optic Cables inet Radio and 3G Communications Systems Multiplexers and Voice Frequency Equipment Remote Terminal Units Substation Grounds Zone Substation Capacitors Zone Substation Circuit Breakers (1) Zone Substation Instrument Transformers Zone Substation DC Supply Systems Zone Substation Disconnectors and Buses (1) Zone Substation Protection Systems Zone Substation Transformers (1) Power Quality Monitoring Systems Metering GPS Clocks Tools and Equipment Vehicles and Fleet Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 17

34 2 NETWORK DEVELOPMENT PROCESS AND DRIVERS (1) Condition based risk management model (2) LV fuse is a consumable device and is typically run to failure. For all other classes of overhead switchgear, condition assessment is conducted as part of routine use via the network operators, during which time notifications are raised for the rectification of defects or replacement of assets as identified. In addition, overhead switchgear is visually inspected every three to four years, and all switches and disconnectors are included in the thermal survey of overhead lines. It is expected that some hot connections and contacts will be detected, and thereby programmed for repair. (3) Major roads public lighting is patrolled three times a year to ensure the lamps are in working order according to Clause (f) of the Public Lighting Code. The patrols are intended to identify defective lamps or sections of lights, lanterns, poles, brackets and ac cess cover plates, which may otherwise remain defective for prolonged periods. (4) Alongside non-major roads, lamps are replaced every four years to ensure sufficient lumens are emitted according to Clause 2.3.1(c) of the Public Lighting Code Technical compliance The services we provide and the operations we carry out are heavily regulated with regard to safety and environmental obligations, as are the service standards we must meet and the prices we can charge. Our principal regulatory bodies are the Essential Services Commission (ESC), Energy Safe Victoria (ESV), the Environment Protection Agency (EPA) and the Australian Energy Regulator (AER). We invest in the network to ensure we meet safety and environmental regulations. We adhere to safety and security standards when we design and undertake work on our assets. We ensure that vegetation growing near our assets does not pose a safety hazard, and in recent years we have been required to implement a number of additional bushfire mitigation measures. We must also comply with various environmental obligations related to vegetation, contaminants, noise, and greenhouse gas emissions. Asset replacement programs have also been developed to ensure that safety and reliability are maintained, and that we meet our safety, environmental and guaranteed service level regulatory and legislative requirements, while we also focus on adhering to our company policies with respect to employee and public safety. System limitations identified through asset management All of the network development projects listed in Section 5.1 have been identified within Jemena s asset management framework. While the majority of proposed projects outlined are related to growth, demand and/or customer connections, the following major projects have been identified through Jemena s asset management condition assessments and the preparation of individual asset class strategies: Continued conversion of the Preston and East Preston supply areas from 6.6 kv to 22 kv, including retirement of Preston Zone Substation (P) by November 2017, and establishment of a new 66/22 kv Preston Zone Substation (PTN) by November Replacement of the three North Essendon Zone Substation transformers with 12/18 MVA 22/11 kv units by November Replacement of the three Fairfield Zone Substation transformers with 12/18 MVA 22/ kv dual secondary winding units by November Replacement of the two Essendon Zone Substation transformers with 20/33 MVA units by November Replacement of Footscray East Zone Substation switchgear by November Replacement of the two Heidelberg Zone Substation transformers with 20/33 MVA 66/11 kv units by November Replacement of Footscray West Zone Substation 22 kv switchgear by November Replacing assets with a different specification (ie: replacing transformers with higher capacity units) is assessed by Jemena within the asset management framework, where it can be demonstrated the change in specification minimises the costs to customers. For example, condition monitoring indicates that the three 22/11 kv North 18 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

35 NETWORK DEVELOPMENT PROCESS AND DRIVERS 2 Essendon Zone Substation transformers are reaching the end of their life, and are planned to be replaced in November 2017 with higher capacity 12/18 MVA units (see section ). The incremental cost to install these higher capacity units is relatively low (approximately $50 thousand) and will mitigate any network limitation within the forecast planning period, while allowing for future demand growth beyond the planning horizon FURTHER INFORMATION Our regulatory proposal, available at Jemena s website 3, includes more detailed information about our asset management framework and approach (Attachment 7-2), our asset management plans (Attachment 7-5) and our 20-year asset management strategy (Attachment 7-6). 2.3 DEMAND FORECASTING METHODOLOGY Load demand forecasting is critical to a network s operation as it is a principal driver of capital expenditure. However, uncertainty always surrounds forecasts due to the inherent unpredictability of factors such as ambient temperatures, weather patterns and, in particular, loads. Load growth can vary from year-to-year and is not uniform across the whole network. It is not unusual to find parts of the network growing at three or four times the average rate for the network as a whole, while other parts of the network can experience periods of no growth at all. Best Practice Distribution Load Forecasting Jemena considers the following features necessary to produce best practice maximum demand, energy and customer number forecasts: Accuracy and unbiasedness careful management of data (removal of outliers, data normalisation) and forecasting model construction (choosing a prudent model based on sound theoretical grounds that closely fits the sample data). Transparency and repeatability as evidenced by good documentation, including documentation of the use of judgment, which ensures consistency and minimises subjectivity in forecasts. Incorporation of key drivers including economic growth, population growth, growth in the number of households, temperature and weather related data (where appropriate), and growth in the numbers of air conditioning and heating systems. Model validation and testing including assessment of statistical significance of explanatory variables, goodness of fit, in-sample forecasting performance of the model against actual data, diagnostic checking of old models, out of sample forecast performance. Jemena also considers the following elements to be relevant to maximum demand forecasting: Independent forecasts Spatial (bottom up) forecasts should be validated by independent system level (top down) forecasts, and both spatial and system level forecasts should be prepared independently of each other. The impact of macroeconomic, demographic and weather trends are better able to be identified and forecast in system level data, whereas spatial forecasts are needed to capture underlying characteristics of specific areas within the network. Generally, the spatial forecasts should be constrained (or reconciled) to system level forecasts; 3 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 19

36 2 NETWORK DEVELOPMENT PROCESS AND DRIVERS Weather normalisation correcting historical loads for abnormal weather conditions is an important aspect of demand forecasting. Long time-series weather and demand data are required to establish a relationship between the two and conduct weather correction; Adjusting for temporary transfers spatial data must be adjusted for historical spot loads arising from peak load sharing and maintenance, before historical trends are determined; Adjusting for discrete block loads large new developments, such as shopping centres and housing developments, should be incorporated into the forecasts, taking into account of the probability that each development might not proceed. Only block loads exceeding a certain size threshold should be included in the forecasts, to avoid potential double counting, as historical demands incorporate block loads; and Incorporation of maturity profile of service area in spatial time series recognising the phase of growth of each zone substation depending on its age, and taking into account the typical lifecycle of a zone substation, helps to inform likely future growth rates. In preparing our peak demand forecasts, Jemena engages an independent consultant for the system level (topdown) forecasts, and prepares the spatial level (bottom-up) forecasts internally. System level forecasts Jemena engaged ACIL Allen to conduct econometric modelling for the 2015/ /25 outlook period, to forecast maximum demand at each terminal station that supplies the JEN network, and for the JEN network region as a whole (top-down). ACIL Allen applies the same forecasting methodology as it developed for AEMO. The system level forecasts prepared by ACIL Allen include a summer and winter demand forecast for Jemena s total network, as well as at each of Jemena s supply terminal stations. For each period (summer and winter) and location a 10%, 50% and 90% POE maximum demand forecast is prepared. The demand drivers the forecast model uses include: An economic outlook for Victoria and for Jemena s supply area, as measured by the Victorian Gross State Product (GSP) growth rate (%) supplied and used by AEMO for the preparation of its 2015 Victorian connection point demand forecasts (refer Figure 2 3 which compares the assumed GSP growth used for the 2015 forecasts, as compared with the 2014 Victorian budget outlook). Solar photovoltaic (PV) generation capacity based on analysis of historical installation rates and estimates of the financial return to solar PV system owners (refer Figure 2 4). Electricity prices, comprising network use of system (NUoS) charges, wholesale electricity costs and other costs such as retail margin applied to electricity sales, supplied and used by AEMO for the preparation of its 2015 Victorian connection point demand forecasts (refer Figure 2 5 which compares the assumed electricity prices used for the 2015 forecasts to the prices used for the 2014 demand forecast). Variation in temperature patterns (weather). 20 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

37 NETWORK DEVELOPMENT PROCESS AND DRIVERS 2 Figure 2 3: Victorian economic growth projections Figure 2 4: Cumulative capacity of installed solar PV systems Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 21

38 2 NETWORK DEVELOPMENT PROCESS AND DRIVERS Figure 2 5: Forecast change in real electricity prices The system level forecast methodology adopted by ACIL Allen Consulting includes: Establishing regression models, to quantify the relationship between electricity demand and its drivers. Producing baseline forecasts, using those models with forecasts of the drivers. Preparation of separate models for each transmission connection terminal station (bottom up) and for demand in Jemena s region as a whole (top down), and reconciliation of the transmission connection terminal station forecasts with the system level forecasts. A post model adjustment to the residential forecasts to account for the impact of the ongoing up-take of solar PV systems. Adjustments were also made to the transmission connection terminal station models before reconciliation to account for a small number of large loads anticipated in certain parts of Jemena s network. The process was conducted separately for summer and winter to produce independent forecasts of maximum demand for each season. Spatial level forecasts The spatial level forecasts prepared internally by Jemena are built up from the feeder level to the zone substation level and then to the transmission connection terminal station level, taking into account diversity at each level of aggregation. Phase 1: Feeder Forecast - The previous year s recorded maximum demand is determined, corrected for abnormalities such as temporary load transfers, and adjustments to correspond to the 50% POE average daily temperature are applied to determine the forecast maximum demand starting point. The overall customer load changes (new or reductions) for each feeder (up to 5 years) are determined based on known new connections, large customer demand changes, local and business developments. The underlying organic growth rate is applied to capture growth resulting from new air conditioning installations in existing dwellings, dual occupancy and minor new or modified loads that have not been allowed for in the overall customer load changes. Feeder forecasts are produced for a minimum of 5 years. 22 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

39 NETWORK DEVELOPMENT PROCESS AND DRIVERS 2 Phase 2: Zone Substation Forecast Similar to Phase 1, the zone substation maximum demand from the previous year is determined, corrected for abnormalities such as temporary load transfers, and adjusted to correspond to the 50% POE average daily temperature. Forecasts are then prepared incorporating overall customer load changes (new or reductions), planned load transfers, and the organic growth rate. Overall customer load changes and load transfers are diversified prior to being included into the zone substation forecasts. Zone substation forecasts are produced for a minimum of 10 years. Phase 3: Terminal Station Forecast - Similar to Phase 2, the terminal station maximum demand from the previous year is determined, corrected for abnormalities such as temporary load transfers, and adjusted to correspond to the 50% POE average daily temperature. Forecasts are then prepared incorporating overall customer load changes (new or reductions), planned load transfers, and organic growth rate. Overall customer load changes and load transfers are diversified prior to being included into the terminal station forecasts. Terminal station forecasts are produced for a minimum of 10 years. Phase 4: Forecast Coincident Demand - Forecasts of demand coincident to the forecast system level maximum demand are required for reconciliation to the top-down forecast. Coincident demand is determined by applying coincidence factors based on historical data to the non-coincident forecast developed in the preceding steps. Phase 5: Forecast Reconciliation - Jemena internal bottom-up forecasts are reconciled with the independent external top-down forecasts at the system level to account for factors such as government policies and economic conditions that are not captured by the bottom-up forecasts. The process for reconciling the forecasts to the system level involves determining the reconciliation factors at each network level and applying them to the non-coincident bottom up forecasts. Spatial level forecasts are produced for summer and winter maximum demand periods. For each period a 10% and a 50% POE maximum demand forecast is prepared. Jemena adopts its spatial forecasts for network planning, due to the planning need for forecasts at the feeder and zone substations level. Accurate spatial forecasts are critical for Jemena to achieve outcomes that are consistent with the NEO, the RIT-D requirements, and the capital expenditure objectives in the NER. Inaccurate demand forecasts will result in energy at risk forecasts that are biased downwards or upwards, depending on whether the forecast demand growth was higher or lower than the actual. Consequently, without accurate spatial forecasts, efficient investment would not occur and customers would be exposed to outcomes that are uneconomic, including increased risk of supply interruptions. In preparing the impact of customer load changes on its spatial forecasts, Jemena considers proposed major industrial and commercial developments, predicted housing and industrial lot releases, and proposed embedded generation. Other items, such as economic forecasting, council planning and various Precinct Structure Plans conducted by the Metropolitan Planning Authority 4, are also taken into account. The principal developments driving significant demand growth in specific locations on the JEN network are outlined in Table See for the Plan Melbourne report. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 23

40 2 NETWORK DEVELOPMENT PROCESS AND DRIVERS Table 2 4: Key JEN Network Developments Zone Substation Kalkallo and Somerton Section and Description Development of underground residential distribution (URD) and industrial estates in the Kalkallo, Craigieburn and Mickleham areas covered by the Northern Growth Corridor Sydenham Proposed new VicTrack workshop in Diggers Rest and continued URD estate developments Sunbury Continued URD and commercial estate developments Coolaroo Continued expansion of URD estates within the Greenvale area Melbourne Airport Customer substation New commercial development within Melbourne Airport Business Park Footscray East New high-rise residential and office buildings within the Footscray Central Activities District Airport West and Tullamarine and On-going commercial and industrial estate developments Fairfield Redevelopment of the Amcor site in Fairfield to multiple high-rise residential and office buildings Airport West Coburg South Coburg North Essendon Airport Development On-going URD and commercial developments within the Pentridge area On-going developments at the CSL site Transmission connection point forecasts Forecasts for the transmission connection points are explicitly included in the TCPR. 24 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

41 NETWORK DEVELOPMENT PROCESS AND DRIVERS NETWORK PLANNING METHODOLOGY This section provides an overview of the network planning methodology applied by Jemena to assess network limitations and identify proposed and preferred solutions to mitigate network limitation risks PLANNING STANDARDS Jemena is required to conduct its planning in accordance with the NER and the Victorian Electricity Distribution Code (EDC). Clause 5.13 of the NER requires Jemena to: Prepare forecasts, covering the forward planning period, of maximum demands for zone substation, subtransmission lines and primary distribution feeders (where practicable). Identify, based on the outcomes of the forecasts, limitations on its network. Identify whether corrective action is required to address any system limitations and, if so, identify whether Jemena is required to carry out the requirements of the regulatory investment test for distribution (RIT-D) 5 and demand side engagement obligations. Take into account any jurisdictional legislation. Clause 3.1 of the EDC requires Jemena to use best endeavours to develop and implement plans for the acquisition, creation, maintenance, operation, refurbishment, repair and disposal of its distribution system assets and plans for the establishment and augmentation of transmission connections: To comply with the laws and other performance obligations which apply to the provision of distribution services. To minimise the risks associated with the failure or reduced performance of assets. In a way which minimises costs to customers taking into account distribution losses. To satisfy these obligations, Jemena applies both probabilistic and deterministic methodologies to the planning of its network PROBABILISTIC METHOD The probabilistic method is applied to network assets with the most significant constraints and associated augmentation costs, including: Transmission connection points. Sub-transmission lines. Zone substations. High-voltage (HV) feeder lines when demand is forecast up to the maximum safe loading limit. The probabilistic method: Directly measures customer (economic) outcomes associated with future network limitations. 5 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 25

42 2 NETWORK DEVELOPMENT PROCESS AND DRIVERS Provides a thorough cost-benefit analysis when evaluating network or non-network augmentation options. Estimates expected unserved energy (EUSE), which is defined in terms of megawatt hours (MWh) per annum, and expresses this economically by applying a value of customer reliability ($/MWh). EUSE estimates the: Long-term probability weighted, average annual energy demanded by customers but not supplied. Future degradation of electricity supply reliability as demand grows or changes. The EUSE measure is then translated into an economic value, suitable for cost-benefit analysis, using the value of customer reliability (VCR), which reflects the economic cost per unit of unserved energy. Figure 2 6 shows how EUSE is used within the broader context of network planning. Figure 2 6: Overview of the probabilistic approach and the broader network-planning task To determine an augmentation option s economic benefits the: EUSE estimate is applied to each credible augmentation option (network, non-network, and do-nothing) determined via the options development process. The change in each option s EUSE, relative to the donothing case, establishes the augmentation option s economic benefit. Economic benefit is compared to each option s costs using discounted cash flow techniques to determine the net benefit. Other quantifiable risks and costs that impact the National Electricity Market (NEM) can also be determined and evaluated through this cost-benefit analysis to establish changes to existing service target performance incentive scheme (STPIS) measures, electricity losses and asset renewal needs. Unquantifiable risks and benefits can be qualitatively considered when selecting the preferred option. The probabilistic planning methodology is made up of four key stages: 26 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

43 NETWORK DEVELOPMENT PROCESS AND DRIVERS 2 Network limitation assessment, which involves determining the extent of network constraints for various network contingency and demand forecast scenarios. Energy at risk analysis, where the maximum energy that is at risk of not being supplied due to these network constraints is determined. Expected unserved energy (EUSE) calculation, which considers the probability of the forecast demand and network condition (contingency) occurring. Cost of EUSE, where the EUSE is transformed into a dollar cost by multiplying the value of customer reliability (VCR) by the expected unserved energy Network limitation assessment A network limitation is assessed by comparing the peak asset loading, under a range of different scenarios and network contingencies, with the asset s rating for each year in the forward planning period. The comparison identifies the extent of the asset overload that will occur without corrective action. A series of inputs and assumptions are associated with the probabilistic method s limitation assessment stage: Maximum demand scenarios, which form a critical input for defining the maximum asset loading, and incorporate the: Season (winter and/or summer). Although the JEN network is typically summer peaking both periods are assessed because there may be some circumstances when a winter peak will exceed the relevant winter rating. Probability of exceedence (POE), which defines the likelihood that the actual maximum demand (and resulting EUSE) will differ from the forecast due to more extreme or benign temperature conditions. Economic growth assumptions, which define the likelihood that the actual maximum demand (and resulting EUSE) will differ from the forecast due to different economic growth outcomes. Levels of embedded generation and demand-side support, which can affect the asset loading. However, without the necessary network support contracts, embedded generation cannot be relied on and, for the purpose of the DAPR limitation assessments, is assumed to not be generating at the time of maximum demand. Contingencies, which can significantly affect asset loading. The DAPR assessments consider loading for both system-normal conditions and following the most credible single contingency. Pre and post-contingent operator actions, which can affect asset loading and the maximum load limit, and therefore the EUSE. Operator action considerations incorporate: Reasonable expectations of what may actually occur at an operational level given the relevant contingent conditions, and allowing for: Available reactive plant switching and control schemes to operate appropriately. The use of available load transfer capacity that is consistent with the asset s thermal rating assumptions. Asset thermal ratings, which typically define the loading limit and are selected to reflect the assumed contingency conditions. Power quality obligations, which under some circumstances, such as a steady state voltage limitation, can define the loading limit. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 27

44 % of maximum demand 2 NETWORK DEVELOPMENT PROCESS AND DRIVERS Power flow modelling is used to determine the relationship between asset loading and contingency conditions, particularly in circumstances where the loading share between parallel assets is uneven, or the loading limit is defined by a power quality obligation Energy at risk analysis Energy at risk: Represents the total energy that is at risk of not being supplied under contingency events, particularly around the maximum demand period. Can be approximated by using a load duration curve that reflects the maximum demand scenario for a given transmission connection terminal station, zone substation or asset. Energy at risk is calculated as the amount of energy above the load duration curve s asset load limit (where the load limit is typically the asset s N-1 rating). The load duration curve is typically based on historical hourly load data scaled to the forecast maximum demand. Energy at risk is calculated for each maximum demand scenario and contingency for each year of the outlook period. Figure 2 7 shows a load duration curve with a horizontal line representing the load limit of a specific contingency. Figure 2 8 shows the same figure, magnified around the part of the load duration curve closest to maximum demand. This effectively illustrates the energy at risk calculation, which is represented by the area under the load duration curve and above the load limit. Figure 2 7: Load duration curve and load limit relationship load duration curve load limit % of time 28 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

45 % of maximum demand NETWORK DEVELOPMENT PROCESS AND DRIVERS 2 Figure 2 8: Energy-at-risk calculation for the area of the load duration curve above the load limit 100 load duration curve load limit energy at risk % of time The calculation s main assumption involves the expected load profile, which: Reflects the maximum demand forecast scenario. Is based (for the DAPR assessments) on an average of the past ten years of historical demand data at the transmission connection terminal station level, measured on an hourly or half-hourly basis Expected unserved energy (EUSE) calculation For a specific maximum demand scenario and contingency, the EUSE measure in megawatt hours (MWh) is the product of the: Energy at risk calculated for a given network state. Probability of being in that network state. In other words, it is the probability that the network will be in a particular condition (system normal or contingency) for a given maximum demand scenario. Total EUSE The total annual EUSE measure is the sum of that year s EUSE measures for each network state. The total EUSE = (E@R c,d p c p d ), across all possible states of c and d; where: E@R c, d represents the energy at risk measure for a given state, c, is the contingency condition with the probability of being in that state, p c, and d, is the maximum demand scenario with the probability of that scenario, p d. The assumptions associated with calculating the total EUSE are: The probability weighting maximum demand scenarios for the DAPR assessments, Jemena has weighted two maximum demand scenarios. The 10% probability of exceedence (POE) scenario is weighted 30% and the 50% POE scenario is weighted 70%. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 29

46 2 NETWORK DEVELOPMENT PROCESS AND DRIVERS The contingency probability this is typically approximated by the ratio of the contingency event rate (events per annum) multiplied by the typical duration of a contingency event to the total number of hours in a year (8,760). These parameters are selected to represent the relevant contingency conditions assumed in the network constraint analysis stage. For the DAPR, the contingency probabilities applied include the: Transformer outage probability, which is 0.217%, and comprises an outage frequency of one outage per transformer every 100 years and lasting an average duration of 2.6 months per outage. Sub-transmission line outage frequency, which is 0.1 outages per kilometre of line length per year and lasting an average duration of 4 hours per outage Cost of EUSE The cost of EUSE is established by multiplying the EUSE calculation by an appropriate value of customer reliability (VCR), where the VCR is: The most appropriate for the assets being assessed and the customer base they supply. Based on values derived and published by the Australian Energy Market Operator (AEMO) or another appropriate body. For the DAPR assessments Jemena has calculated a VCR of $38,950/MWh (in 2015 Australian dollars) to be applied to all limitation assessments. This VCR was developed using AEMO s 2014 value of customer reliability review 6 and applying Jemena s customer load composition, comprising an approximate 31% residential, 46% commercial and 23% industrial split. It includes an escalation factor of 1.33% to account for CPI from AEMO s 2014 values Treatment of losses An increase or decrease in power losses are accounted for in the economic evaluation of network augmentation and asset replacement projects. Network power loss changes are inherently accounted for through power system analysis as the change in network loading, and therefore expected unserved energy, due to network impedance changes of newly installed, removed or altered assets. The benefits, positive or negative, of power loss changes are included in the change in expected unserved energy calculations; however they are not separately reported in our assessments due to the complexity and limited benefit in doing so. Power losses are typically only material in areas of the network supplying long sub-transmission circuits or feeders, which are scarce but do exist in some of the more rural areas to the north of our network. Since power losses are typically immaterial within our network, and are generally insufficient to justify augmentations without additional identified benefits, Jemena does not generally approach a potential reduction in power losses as an investment driver in itself. Where network losses do have a material impact the benefits of augmentation or asset replacement are commonly identified through other network supply risks, such as expected unserved energy assessments, and the benefits are identified by comparing the reduction in expected unserved energy that each credible option can deliver. Similarly, when considering augmentations to increase the power factor at customer supply points, such as installing new capacitor banks at zone substations, the reduction in network losses due to the removal of reactive power flows from the bulk transmission supply point, will be reflected in the increased capacity to meet customer demand, again reducing load curtailment and any expected unserved energy. 6 AEMO Value of customer reliability review. Available at Reliability-review 30 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

47 NETWORK DEVELOPMENT PROCESS AND DRIVERS 2 For new feeders, or when upgrading a section of an existing feeder to increase its capacity, Jemena selects conductors that are optimised for the expected maximum load the feeder is intended to carry in the forward planning period. While oversizing conductors will invariably lead to lower power losses, the additional asset and installation costs are rarely offset by the reduction in power losses DETERMINISTIC METHOD The deterministic method: Determines the need for augmentations using criteria that define the maximum permissible loading on assets, rather than by explicitly measuring customer outcomes. Is used for high-voltage (HV) feeders where load is forecast to exceed the maximum safe loading limit. Is used for distribution substations and associated low-voltage (LV) networks. Makes no allowance for contingent conditions because these assets generally have a lower standard of load control and monitoring. The deterministic planning criteria are set to approximate the prudent timing for when additional network or nonnetwork capacity is required, and are predominantly based on two key drivers: Maintaining the safe operation of assets. Maintaining the supply reliability and quality provided by these assets under system normal conditions (with all network assets in service). Three key assumptions and criteria are associated with this method: The maximum demand forecast scenario, where only the 10% POE scenario is applied. The network condition being considered. Given that this method only applies to HV feeders and distribution substations, only the system normal condition is assessed. The loading limit, which represents the maximum permissible loading (relative to a reference thermal rating) for the assumed maximum demand forecast. For the DAPR assessments a loading limit of 100% of the HV feeder s capacity has been applied to the deterministic assessment methodology. The deterministic method s risk/cost trade-off can be viewed in terms of the relationship between the maximum demand scenario s probability of exceedence assumption, the asset loading, and the assumed rating. For HV feeders, the deterministic method only applies for forecast load above the maximum safe loading limit after accounting for load transfers to adjacent feeders. The determination of the maximum safe loading limit is based on the conductor s and/or cable s maximum operating temperature, at which point these assets deteriorate rapidly to an unacceptable level, or a statutory clearance limit is expected to infringe on the asset s safe operation. A fixed wind speed of 0.6 m/s is typically assumed in limit determination calculations. Jemena is working to incorporate energy consumption data from AMI meters into its substation utilisation profiling system (SUPS). This will improve the accuracy of forecasting load on distribution substations and associated LV networks. This work is on-going, with enhancement planned in the period. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 31

48 3 NETWORK PERFORMANCE 3. NETWORK PERFORMANCE This section describes the service target performance incentive scheme (STPIS), and the reliability performance indicators used to assess Jemena s network performance. It includes a summary of how Jemena s electricity network has performed against these targets, presents forecast performance targets, and summarises corrective action being taken to ensure appropriate levels of performance are maintained. This section also considers Jemena s power quality obligations, comprising steady state voltage, voltage variations, harmonics, unbalance and flicker. Both historical and forecast power quality performance for Jemena s network is considered. 3.1 NETWORK PERFORMANCE INDICATORS Delivering a reliable electricity supply to our customers is core to Jemena s business. In line with the STPIS, Jemena continuously monitors its network performance using the international reliability measures and standards presented in Table 3 1. Using these indicators to track and compare our performance enables us to identify network performance issues and initiate required investments to maintain appropriate reliability levels. Table 3 1: Reliability measures and standards Index Measure Description System Average Interruption Duration Index (SAIDI) System Average Interruption Frequency Index (SAIFI) Momentary Average Interruption Frequency Index (MAIFI) Average off supply minutes per customer Average number of interruptions per customer Average number of momentary interruptions per customer The average total minutes that a customer could expect to be without electricity over a specific period. Total SAIDI comprises both planned and unplanned off supply minutes. The average number of occasions per year when each customer could expect to experience an unplanned interruption. SAIFI is calculated as the total number of customer interruptions divided by the total number of connected customers averaged over the year. Unless otherwise stated, SAIFI excludes momentary interruptions (less than one minute duration). The average total number of momentary interruptions (less than one minute duration) that a customer could expect to experience in a year. MAIFI is calculated as the total number of customer interruptions of less than one minute duration, divided by the total number of connected customers averaged over the year. 32 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

49 NETWORK PERFORMANCE HISTORICAL NETWORK PERFORMANCE Jemena continually monitors network performance and internally reports actual performance against STPIS targets on a monthly basis. All aspects of Jemena s business, from asset management and investment strategies to network control and monitoring, contribute to network performance and have resulted in all three STPIS key performance indicators being met in Given our ongoing effort to maintain network reliability levels, and having experienced benign weather conditions in 2014/15, with the maximum demand tracking close to our 90% probability of exceedence (POE) maximum demand forecast, performance close to our targets is as expected. Table 3 2 summarises our network performance for 2014, compared to the performance indicators set by the Australian Energy Regulator (AER) under the STPIS. Table 3 2: 2014 network performance Measure Urban Target Rural- Short Urban Actual Rural- Short Unplanned System Average Interruption Duration Index (SAIDI) Unplanned System Average Interruption Frequency Index (SAIFI) Momentary Average Interruption Frequency Index (MAIFI) Figure 3 1 shows Jemena s historical network performance for unplanned SAIDI (between 1995 and 2013) compared to the regulator s performance targets from year Figure 3 1: Historical unplanned SAIDI network performance ( ) Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 33

50 3 NETWORK PERFORMANCE 3.3 NETWORK PERFORMANCE TARGETS As part of Jemena s regulatory proposal submitted to the AER in April 2015, Jemena intends to maintain current performance levels. Performance targets for the regulatory period are therefore based on actual network performance measured between 2010 and This target setting methodology is the same as that used by the AER to determine the targets. The AER will set network performance targets for the regulatory period in its final determination which is due by the end of April Table 3 3 presents Jemena s annualised performance targets for the period. Table 3 3: network performance targets Measure Urban Rural- Short Unplanned System Average Interruption Duration Index (SAIDI) Unplanned System Average Interruption Frequency Index (SAIFI) Momentary Average Interruption Frequency Index (MAIFI) In the AER s proposed application of the STPIS for the 2016 regulatory period, detailed in its final framework and approach paper, the Momentary Average Interruption Frequency Index (MAIFI) was not included as a performance indicator. Jemena have proposed that the MAIFI performance indicator be included as an additional parameter within the s-factor as required in the STPIS scheme in its regulatory proposal FORECASTING NETWORK PERFORMANCE Jemena s capital and operational expenditure plans are based on the principle of maintaining network reliability performance. Network performance forecasts are therefore prepared following the same principle of aiming to meet the performance targets over the long term. Any reduction in our approved capital expenditure allowance would therefore result in a proportional reduction in network reliability, and would require re-forecasting to reflect this impact. 7 Section 3.1(f) of AER, Electricity distribution network service providers Service target performance scheme, November 2009, requires the MAIFI parameter to be included in the calculation of s-factor if the parameter can be measured. In Victoria this parameter has been recorded for the 2011 Regulatory Period and therefore must be included in the scheme design for the 2016 Regulatory Period 34 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

51 NETWORK PERFORMANCE NETWORK PERFORMANCE CORRECTIVE ACTION Network performance improvement initiatives differ from traditional network augmentations or asset replacements. Where network augmentation and asset replacement traditionally focusses on developing the network to meet demand growth and maintain a reliable service, network performance improvements can either be forward looking or more reactionary. Monitoring network performance against performance targets, investigating, analysing and trending network outage causes, and undertaking initiatives to counteract identified issues, network performance improvement initiatives undertaken by Jemena typically include: Installing tie-lines between heavily loaded radial/spur feeders that lack emergency transfer capacity. Optimising feeder loads and customer numbers to minimise fault impacts. Installing remote monitoring fault indicators, to quickly identify fault locations. Installing remote-controlled switching devices, including automatic circuit reclosers (ACRs), to minimise network fault impacts by reducing customer interruptions and quickly restoring supply to the healthy section. Implementing pole fire mitigation techniques. Proofing the network against animal interference. Identifying and replacing or phasing out fault-prone assets. With performance in 2014 closely aligned to performance targets (see Table 3 2), Jemena s network performance augmentations in the planning period will primarily focus on maintaining current performance levels. During the forward planning period, works will include reconfiguring feeders to balance loads, establishing feeder tie-lines where emergency transfer capacity is not adequate, and installing remote monitoring fault indicators and controlled switching devices to quickly identify fault locations and restore load following a network outage. Location-specific network performance works are detailed in Jemena s network development plan (see Section 5), and include: Establishing a tie-line between SBY-32 and SBY-11 by November Establishing a tie-line to COO-11 by November Establishing a tie-line to FF-89 by November Reconfiguring two spurs (radial sections) on feeder KLO-22 by November Replace non tension connectors at BD by November Replace surge diverters at BD by November QUALITY OF SUPPLY Jemena is required to comply with the requirements in Section 4 of the EDC, and Schedule S5.1a of the NER. Given a customer can connect anywhere on the network, Jemena endeavours to maintain quality of supply levels in line with our requirements at all possible connection points in the network. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 35

52 3 NETWORK PERFORMANCE Steady state voltage and voltage variations Clause 4.2 of the EDC specifies the requirements for steady state voltages, voltage variations (sags and swells) and impulses (transients) at customers supply points, which is summarised in Table 3 4. Table 3 4: EDC standard nominal voltage variations Voltage Steady State Less than 1 minute Less than 10 seconds Ph-E Ph-Ph < 1.0 kv +10 % - 6 % +14% - 10% +50% -100% +20% -100% 1 22 kv ± 6 % (± 10 % Rural Areas) ± 10 % +80% -100% +20% -100% 66 kv ± 10 % ± 15% +50% -100% +20% -100% Clause S5.1a.4 of the NER requires a steady state voltage of ±10%, and an overvoltage limit due to a contingency event as described by Figure 3 2, which is an extract of Figure S5.1a.1 in the NER. Figure 3 2: NER overvoltage limit due to a contingency event Harmonic voltage distortion Table 3 5 summarises the requirements for voltage harmonic levels at the customers supply points, which are described by: Clause 4.4 of the EDC. This requirement is based on the former Australian standard AS2279.2, which was withdrawn by most Australian states in Clause S5.1a.6 of the NER, which requires compliance with AS/NZS Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

53 NETWORK PERFORMANCE 3 The EDC is more stringent for total harmonic distortion (THD) and low frequency harmonics for which the JEN network is likely to experience, whereas the NER is more stringent for higher frequency harmonics. Table 3 5: Harmonic levels at customer supply points VDC NER THD Odd harmonics Even harmonics THD Odd harmonics Even harmonics Low voltage (< 1 kv) 5 % 4 % 2 8 % 3 rd = 5 % 5 th = 6 % 7 th = 5 % 2 nd = 2 % 4 th = 1 % 6 th = 0.5 % For higher orders refer AS/NZS :2001 Medium / High voltage (> 1 kv) 3 % 2 % 1 Voltage unbalance (negative sequence voltage) Table 3 6 summarises the requirements for voltage unbalance, defined by the negative phase sequence voltage, at the customers supply points, which are described by: Clause 4.6 of the EDC. Clause S5.1a.5 of the NER. The voltage unbalance requirements of the EDC are more stringent than the NER. Table 3 6: Voltage unbalance at customer supply points VDC NER 30 min average 10 min average 1 min average (once per hour) < 10.0 kv 1 % 2 % 2.5 % 3 % > 10 kv 1.3 % 2 % 2.5 % Flicker (disturbing load) Table 3 7 summarises the requirements for voltage flicker at the customers supply points, which are described by: Clause 4.8 of the EDC. This requires compliance with AS/NZS for LV systems, and AS/NZS for MV and HV systems. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 37

54 3 NETWORK PERFORMANCE Clause S5.1a.5 of the NER, which specifies identical requirements but also specifies that the DNSP must define the planning levels. Table 3 7: Flicker at customer supply points Voltage PST PLT < 1.0 kv kv kv Power quality monitoring coverage Every JEN network zone substation has at least one power quality monitoring device permanently installed on site. A power quality monitoring device is also installed at the far end of one high voltage distribution feeder emanating from each zone substation, usually the longest feeder. Furthermore, the recent completed rollout of smart meters has allowed basic power quality monitoring of the customer connection points in the low voltage distribution system HISTORICAL NETWORK QUALITY OF SUPPLY The MV steady state voltage performance of each 22 kv and 11 kv zone substation over the 2014/15 financial year is summarised in Figure 3 3. The performance of each 6.6 kv zone substation is summarised in Figure 3 4. The results show that while Jemena s MV supply voltage is on the high side of the allowable range, the majority of zone substations compliant 98% of the time. Figure 3 3: Steady state voltage performance 22 kv & 11 kv sites 38 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

55 NETWORK PERFORMANCE 3 Figure 3 4: Steady state voltage performance 6.6 kv sites Voltage sags and swells are recorded by the permanent power quality meters installed at the zone substations only. While swell is not a common occurrence, the sag performance of each zone substation over the 2014/15 financial year is summarised Figure 3 5. Figure 3 5: Voltage sags and swells Harmonics are recorded by the permanent power quality meters installed at the zone substations only. To date a number of problematic sites have been identified that are beyond EDC limits. Results for each 22 kv and 11 kv zone substation for the 2014/15 financial year are presented in Figure 3 6. Results for each 6.6 kv zone substation are presented in Figure 3 7. These results show that the total harmonic distortion (THD) is below the 3% EDC limit at the majority of zone substations. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 39

56 3 NETWORK PERFORMANCE Figure 3 6: Harmonic distortion levels 22 kv & 11 kv sites Figure 3 7: Harmonic distortion levels 6.6 kv sites Voltage unbalance is recorded by permanent power quality meters installed at Jemena s zone substations. Results for each 22 kv and 11 kv zone substation for the 2014/15 financial year are presented in Figure 3 8. Results for each 6.6 kv zone substation are shown in Figure 3 9. The results show that the majority of zone substations have an unbalance level below the 1% EDC limit. Figure 3 8: Voltage unbalance (negative sequence voltage) 22 kv & 11 kv sites 40 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

57 NETWORK PERFORMANCE 3 Figure 3 9: Voltage unbalance (negative sequence voltage) 6.6 kv sites Although flicker cannot be directly measured due to measurement limitations of Jemena s power quality meters, the University of Wollongong has calculated flicker levels using the raw data recorded by the meters. Long-term and short-term flicker measurement results for the 2014/15 financial year, presented in Figure 3 10 and Figure 3 11, indicate that Jemena is compliant at the MV sites where power quality is monitored. Figure 3 10: Voltage flicker levels Pst distribution Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 41

58 3 NETWORK PERFORMANCE Figure 3 11: Voltage flicker levels Plt distribution 3.6 POWER QUALITY CORRECTIVE ACTION With power quality performance in 2014/15 generally within the regulatory requirements, Jemena s power quality corrective action is primarily focussed on monitoring and maintaining existing power quality levels, while slightly reducing the steady state voltage levels at specific zone substations through network operational action. Specific works to address, steady state voltage and voltage variations in Jemena s network development plans include: Voltage regulators for SBY-11 and SBY-32 (section ). Various capacitor bank installations at different zone substations for both reactive and transformer loading limitations. Lowering the 11 kv voltage set point at North Essendon Zone Substation to avoid overvoltage issues at the zone substation and on the feeder lines. There are no specific works to address harmonic distortion, voltage unbalance, or voltage flicker detailed in Jemena s network development plans. 42 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

59 NETWORK DEMAND FORECASTS 4 4. NETWORK DEMAND FORECASTS This section presents Jemena s network wide historical actual demand, compares the 2015 summer maximum demand forecasts with the forecasts published in the 2013 DAPR and 2014 DAPR, and presents the 2015 summer and winter maximum demand forecasts. Demand forecasts for Jemena s connection points can be found in the 2015 TCPR, which is available on Jemena s website CHANGES TO DEMAND FORECASTS Figure 4 1 shows the historical summer maximum demand on Jemena s electricity network since 2003 and a comparison of the 2013, 2014 and current (2015) ACIL Allen system level (top-down) maximum demand forecasts for the JEN region over the 2015/ /25 outlook period. Figure 4 1: Jemena network maximum demand forecast comparison 8 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 43

60 4 NETWORK DEMAND FORECASTS 4.2 FORECAST DEMAND The growth in demand across Jemena s network is generally slowing, with the total network maximum demand forecast to grow at an average rate of just 1.02% per annum between 2016 and 2021, which is largely being driven by a projected return to trend GDP growth and a stabilisation of electricity prices, compared to a historical average growth rate of 2.7% per annum between 2004 and Table 4 1 presents the summer and winter ten year maximum demand forecasts for both 10% POE and 50% POE conditions. The forecasts are also presented in Figure 4 2, along with the historical actual demand since Table 4 1: Jemena network maximum demand forecast Demand (MW) Actual Forecast Average annual growth Summer (50%POE) Winter (50%POE) Summer (10%POE) Winter (10%POE) % % % % 44 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

61 NETWORK DEMAND FORECASTS 4 Figure 4 2: Jemena network historical and forecast maximum demand Despite the general slowing in demand growth at the network level, there are areas within the network where maximum demand is forecast to grow well beyond the network average. Similarly, other parts of the network are forecast to experience a decline in forecast demand as a result of manufacturing closures, for example Ford Motors in Broadmeadows, and continued uptake of solar photovoltaic generation, which acts to offset demand growth at a residential level. In general, Jemena expects strong demand growth in the northern half of its network, largely due to new developments associated with urban sprawl towards the edge of the Urban Growth Boundary. As a result of this urban sprawl and the recent extension of the Urban Growth Boundary, Jemena expects strong demand growth to continue over the next six years in the areas currently supplied by zone substations at Kalkallo (maximum demand forecast to grow at an average of 8.8% per annum over the next six years), Somerton (4.0%), Sydenham (2.1%), Sunbury (3.0%), and Coolaroo (1.9%). Some pockets within established inner suburbs are also experiencing strong demand growth as a result of amendments to the planning schemes to allow high density living. The high growth is predominately driven by the development of high rise residential and office buildings, and the expansion of community facilities and services, such as around the Footscray Central Activity District, Essendon Airport and Melbourne International Airport. As a result, Jemena is forecasting high growth in maximum demand, over the next six years, for areas currently supplied by zone substations at Tullamarine (maximum demand forecast to grow at an average of 5.5% per annum over the next six years), Fairfield (2.8%), Footscray East (2.3%), Airport West (2.1%), and Coburg South (1.7%). Jemena expects other parts of the network, generally in the south, to experience low growth or even a decline in maximum demand. Table 4 2 summarises the expected growth across Jemena s electricity network over the next six years. These growth areas are also presented geographically in Figure 4 3. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 45

62 4 NETWORK DEMAND FORECASTS Table 4 2: Supply area average annual growth over the next five years ( ) Supply area average annual growth ( ) Season Strong growth (>5% p.a) High growth (3-5% p.a) Medium growth (1-3 % p.a) Low growth and possible decline (<1% p.a) Summer Kalkallo, Tullamarine, Watsonia Somerton, Sunbury Airport West, Coburg South, Coolaroo, Fairfield, Flemington, Footscray East, Sydenham, Yarraville Braybrook, Broadmeadows, Broadmeadows South, Coburg North, East Preston, Essendon, North Essendon, Footscray West, Heidelberg, North Heidelberg, Newport, Pascoe Vale, Preston, St Albans, Thomastown, Tottenham 46 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

63 NETWORK DEMAND FORECASTS 4 Figure 4 3: Forecast demand growth by zone substation supply area Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 47

64 5 NETWORK DEVELOPMENT 5. NETWORK DEVELOPMENT This section outlines existing and emerging network limitations identified throughout the planning review process, and information about recently completed projects and committed network developments covering the forward planning period (2016 to 2020). These existing and emerging limits can be a result of asset condition, thermal and fault level capacity, or power quality issues. To facilitate non-network service provider solutions, the expected impact of identified limitations are outlined, including the hours per year that load is at risk of not being serviced due to a network limitation, and the amount of load reduction that would be required to defer or mitigate risks associated with each network limitation. Potential solutions to mitigate network limitation risks are also presented, along with the augmentation option and timing that Jemena considers most likely to occur based on the option s ability to economically maximise the reliable supply of electricity. In all cases, solutions will include asset replacements, refurbishments, or augmentations. All costs presented in this DAPR are total project costs and are presented in Real $2015, unless otherwise stated. 5.1 NETWORK DEVELOPMENT OVERVIEW This section presents the proposed preferred development options and their indicative timing to manage the identified network limitations outlined in Sections 5.6 and 5.7. This development plan is based on current network conditions and Jemena s 2015 Load Demand Forecasts Report. Other than Table 5 1, which presents 2016 committed projects, development proposals are uncommitted and still subject to Jemena s project approvals process and procurement of appropriate funding. Any party considering an investment (or potential deferral of a proposed investment) based on this development plan should first consult Jemena for specific, detailed, and up-to-date network development information. There are no augmentations with an estimated capital cost of $2 million or more in the forward planning period that are to address an urgent and unforeseen network issue. Table 5 1 lists the committed network development projects for Table 5 1: 2016 network development plans Network limitation Preferred network solution Project Reference Number (See Figure 5 1 for major project locations) Section reference SHM-14 thermal capacity Install a new SHM feeder (SHM-22) P and EP asset condition and thermal capacity Stage 4 of Preston area and East Preston area conversions and ES-15 and ES-24 thermal capacity ST-22 and ST-32 thermal capacity Reconfigure ES-23 feeder loads 3 0 Reconfigure ST-11 and ST-22 feeder loads Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

65 NETWORK DEVELOPMENT 5 Network limitation Preferred network solution Project Reference Number (See Figure 5 1 for major project locations) Section reference BD-03 and BD-04 thermal and transfer capacity Reconfigure BD4, BD3 and BMS21 feeder loads High bushfire risk area Install REFCL at SHM AW relay asset condition Replace relays at AW YVE-21 and YVE-22 thermal and transfer capacity Establish a tie line between YVE-21 and YVE-22 and reconfigure feeder loads Table 5 2 through to Table 5 5 presents Jemena s proposed network development plans for the period Table 5 2: 2017 network development plans Network limitation Preferred network solution Project Reference Number (See Figure 5 1 for major project locations) Section reference BTS-NS-BTS 66 kv loop thermal capacity CS-02 and CS-05 thermal and transfer capacity Augment BTS-NS 22 kv loop Augment feeder CS SBY-14 thermal capacity Augment feeder SBY SBY-32 back-up supply capacity Establish a tie line between SBY-32 and SBY FT asset condition and thermal capacity Redevelop FT by replacing FT 11 kv transformer cables and installing three new 11 kv buses at FT CS transformer and TTS-CN- CS-TTS 66 kv loop thermal capacity Install an 8 MVAR capacitor bank at CS and FT-02 thermal capacity Install a new FT feeder HB-14, HB-15 and HB-22 thermal capacity PV-14, PV-22 and PV-31 thermal capacity Install a new HB feeder (HB-21) Install a new PV feeder (PV-11) SBY-14 thermal capacity Install a new SBY feeder (SBY-12) P and EP asset condition and thermal capacity Stage 5 Preston area conversion Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 49

66 5 NETWORK DEVELOPMENT Network limitation Preferred network solution Project Reference Number (See Figure 5 1 for major project locations) Section reference Ongoing supply post Deer Park Terminal Station establishment Purchase No.2 KTS-MLN-SBY 66 kv line and install new conductors to form a new No.2 KTS-SBY 66 kv line SBY thermal capacity limitation Purchase Sunbury site land BMS-12 thermal capacity Re-conductor feeder BMS AW-06 and AW-07 thermal capacity Reconfigure AW-06, AW-07 and AW-08 feeder loads BD-13 thermal capacity Reconfigure BD-13 feeder loads High bushfire risk area Install REFCL at SBY NS transformer asset condition Replace NS transformers BD relay asset condition Replace relays at BD FF supply area thermal capacity Establish three new FF feeders and Table 5 3: 2018 network development plans Network limitation Preferred network solution Project Reference Number (See Figure 5 1 for major project locations) Section reference SBY-32 thermal and back-up supply capacity SBY-11 steady state voltage power quality BY transformer thermal capacity TTS-NEI-NH-WT-TTS 66 kv loop thermal capacity Augment feeder SBY Install a voltage regulator on feeder SBY Install two 8 MVAR capacitor bank at BY Install a 8 MVAR capacitor banks at NH COO-13 thermal capacity Install a new COO feeder (COO-23) KTS-MAT-AW-PV-KTS 66 kv loop thermal capacity Split KTS-MAT-AW-PV-KTS 66 kv loop this project will proceed depending on customer demand supplied at MAT P and EP asset condition and thermal capacity Stage 6 Preston area conversion (establish PTN) AW-03 thermal capacity Reconfigure AW-03 feeder loads Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

67 NETWORK DEVELOPMENT 5 FF supply area thermal capacity SBY condition and thermal capacity Establish a new FF feeder Redevelop SBY FF transformer asset condition Replace FF transformers Table 5 4: 2019 network development plans Network limitation Preferred network solution Project Reference Number (See Figure 5 1 for major project locations) Section reference Feeder and substation thermal and transfer capacity surrounding Craigieburn Establish a new zone substation in the Craigieburn area (CBN) and High bushfire risk area Install REFCL at CBN and EP asset condition and thermal capacity COO-11 back-up supply capacity NH-03, NH-09 and NH-17 thermal and transfer capacity Stage 5 East Preston area conversion Establish a tie line to COO Install a new NH feeder (NH-19) CS-08 thermal capacity Reconfigure CS-02, CS-05 and CS-08 feeder loads AW-03 and AW-11 thermal capacity Reconfigure feeders AW-03, AW-11 and TMA ES transformer asset condition Replace ES transformers 47 0 NH relay asset condition Replace relays at NH FE switchgear asset condition Replace 22 kv switchgear at FE 49 0 Table 5 5: 2020 network development plans Network limitation Preferred network solution Project Reference Number (See Figure 5 1 for major project locations) Section reference TT-10 thermal capacity Augment feeder TT FF-89 supply security and reliability SBY-32 steady state voltage power quality Establish a tie-line to FF Install a voltage regulator on SBY Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 51

68 5 NETWORK DEVELOPMENT TSTS-HB-L-Q-TSTS 66 kv loop thermal capacity and power factor compliance Install an 8 MVAR capacitor bank at HB SHM thermal capacity Purchase land for future establishment of Plumpton Zone Substation (PLN) BY supply reliability for risk of a 22 kv bus outage Reconfigure feeders across 22 kv BY buses KLO-22 back-up supply capacity Reconfigure two spurs (radial sections) on KLO High bushfire risk area Install REFCL at COO HB transformer asset condition Replace HB transformers CN relay asset condition Replace relays at CN FW relay asset condition Replace relays at FW FW switchgear asset condition Replace 22 kv switchgear at FW Figure 5 1 shows Jemena s electricity network, including terminal station supply points, sub-transmission lines and zone substations, and highlights major project locations based on the Project Reference Numbers presented in Table 5 1 through to Table Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

69 NETWORK DEVELOPMENT 5 Figure 5 1: Jemena electricity network (December 2015) and major proposed projects Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 53

70 5 NETWORK DEVELOPMENT CHANGES SINCE 2014 REPORT In the preceding 12 months, Jemena has completed the following major network upgrades: Installation and commissioning of the Broadmeadows South Zone Substation (BMS), which services anticipated load growth in the Broadmeadows South, Jacana and Campbellfield areas, and provides relief to zone substation BD. Installation and commissioning of the new East Preston Zone Substation (EPN), which completes an important step in the ongoing conversion program of at P and EP zone substations from 6.6 kv to 22 kv, to address the deteriorated assets that are in poor condition. Installation and commissioning of the Tullamarine Zone Substation (TMA) which services anticipated load growth in the Airport West and Tullamarine areas, and provides relief to Airport West Zone Substation. Re-conductor the KTS-AW 66 kv line, which reduces the energy at risk for the KTS-MAT-AW-PV-KTS subtransmission loop. Installation and commissioning of a new 11 kv feeder, ES-22, which offloaded 0.5 MVA from FT-10 and provides approximately 6 MVA of emergency load transfer capacity to Flemington Zone Substation. Since publishing the 2014 DAPR, changes to the network development plan are: All costs have been updated to Real 2015 dollars, unless otherwise stated. Preliminary design undertaken for the Flemington Zone Substation supply capacity project shows it is likely that the 11 kv transformer cables can be replaced with higher capacity cables in the existing cable ducts. This means that the proposed works can be undertaken within the existing 11 kv switch-room building, and the revised delivery approach results in reduced estimated project cost. Preliminary design and line survey results have resulted in an increase cost estimate for the planned KTS- MAT-AW-PV-KTS 66 kv loop capacity works. Jemena s investigations into a targeted demand response program in the Footscray East and North Heidelberg supply areas did not identify any viable demand management opportunities SUMMARY OF JOINT PLANNING OUTCOMES TNSP joint planning Table 5 6 summarises the planning outcomes for Jemena s transmission connection points undertaken as part of, and presented in, the 2015 Transmission Connection Planning Report (TCPR), for Jemena s five-year forward planning period. Table 5 6: Jemena Connection Points Connection Point Brunswick Terminal Station (22 kv) Brooklyn Terminal Station (22 kv) 2015 TCPR Outcome No augmentation of capacity is required. No augmentation of capacity is required. Keilor Terminal Station Construction of a new terminal station at Deer Park, to be completed by summer 2017/18. South Morang Terminal Station No augmentation of capacity is required. 54 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

71 NETWORK DEVELOPMENT 5 Templestowe Terminal Station Thomastown Terminal Station West Melbourne Terminal Station No augmentation of capacity is required. No augmentation of capacity is required. Once load has been permanently transferred away to the redeveloped Brunswick Terminal Station (BTS) 66 kv in late 2016, no additional augmentation of capacity is required. There have been no material changes to joint planning undertaken between Jemena and AusNet Services or AEMO in the preceding year. The construction of Deer Park Terminal Station (DPTS), and the associated upgrades at Keilor Terminal Station (KTS), remains the most significant joint planning exercise undertaken by Jemena 9. DNSP joint planning In the preceding year there were no material joint planning changes for the sub-transmission assets shared by Jemena and surrounding DNSPs, which are listed in Table 2 1. There is no sub-transmission investments in the forward planning period that are an outcome of the DNSP joint planning process. 5.2 SUMMARY OF RIT-D APPLICATIONS Jemena commenced two Regulatory Investment Tests for Distribution (RIT-Ds) in 2015, and intends to commence a third RIT-D assessment within the forward planning period ( ). The RIT-Ds commenced in 2016 are: Flemington Electricity Supply. Sunbury-Diggers Rest Electricity Supply. The third RIT-D, which Jemena intends on commencing in November 2016, is a review of the Northern Corridor Electricity Supply FLEMINGTON ELECTRICITY SUPPLY On 23 October 2015 Jemena published Stage One, the Non-Network Options Report, of the Flemington Zone Substation Capacity RIT-D. The existing Flemington Zone Substation (FT) supplies customers in the Flemington, Kensington, Ascot Vale and surrounding areas. There is currently insufficient thermal capacity at FT to supply the forecast load, under system normal and network outage conditions. The primary driver of the identified need to augment capacity is the thermal capacity limitations on 11 kv transformer circuit breakers, buses and transformer cables. Under maximum demand conditions load shedding would be required to maintain network loading levels within the ratings of these assets. 9 Powercor is also a key party involved in joint planning for the DPTS. For details, refer to the Joint Regulatory Test Report Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 55

72 5 NETWORK DEVELOPMENT Since publishing the Non-Network Options Report, Jemena has undertaken some preliminary design and assessment to determine the feasibility of augmentation options, which has led to the assessment of additional options including: Option 1a: upgrade 11 kv transformer cables and 11 kv switchboards, and install a third 11 kv switchboard (in new switch-room building); Option 1b: upgrade 11 kv transformer cables and 11 kv switchboards, and install a third 11 kv switchboard (in existing switch-room building); Option 1c: upgrade 11 kv transformer cables and 11 kv switchboards (in new switch-room building); Option 1d: upgrade 11 kv transformer cables and 11 kv switchboards (in existing switch-room building); Option 2: rebuild Flemington Zone Substation; Option 3: establish a new zone substation to upgrade FT; Option 4: install a third 66/11 kv transformer (in existing switch-room building); Option 5: embedded generation and demand management; Option 6: upgrade 11 kv transformer cables (in existing switch-room building); and Option 7: upgrade 11 kv transformer cables and 11 kv transformer circuit breakers (in existing switch-room building). The preliminary design has given us confidence that it is likely that the existing 11 kv transformer cables can be replaced with higher capacity cables in the existing cable ducts. This revised delivery approach means that the proposed works can be undertaken within the existing 11 kv switch-room building. Jemena s assessments show that Option 1b maximises the present value of net economic benefit by reducing network outage risks and increasing network capacity to meet forecast demand. With the proposed works able to be completed in the existing switch-room building, the estimated project cost has reduced to $7.0 million. The project is still planned for completion by November Following implementation of the proposed preferred option, FT capacity will be limited by the existing 66/11 kv transformers, which each have a cyclic rating of 34.8 MVA, or the upgraded 11 kv transformers cables if significantly higher capacity cables cannot be installed in the existing cable ducts An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $460 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. The purpose of the Non-Network Options Report is to seek submissions from interested parties, including proponents of non-network solutions, to meet the emerging needs of the Flemington network by providing the relevant technical characteristics, and is available at Jemena s website 10. Submissions close on 29 January 2016 and can be provided in writing to Mr Ashely Lloyd, Network Capacity Planning and Assessment Manager, at PlanningRequest@jemena.com.au. Jemena intends to publish Stage Two, the Draft Project Assessment Report, of this RIT-D by 30 June Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

73 NETWORK DEVELOPMENT 5 No material impacts on customer connection charges and distribution use of system (DUoS) charges have been identified SUNBURY-DIGGERS REST ELECTRCITY SUPPLY On 23 October 2015 Jemena published Stage One, the Non-Network Options Report, of the Sunbury Diggers- Rest Capacity RIT-D. The existing Sunbury Zone Substation (SBY) supplies customers in the Sunbury and Diggers Rest areas, which are located within the Victorian Government s Urban Growth Boundary, and residential developments are expected to result in an average maximum demand annual grow rate of 3.0% over the next six years. The summer system normal rating of SBY is 32 MVA, while the forecast 50% POE summer maximum demand in 2015/16 is 38.9 MVA, rising to 51.3 MVA by 2024/25. Since the 2012/13 summer, Jemena has performed load transfers to nearby zone substations Sydenham (SHM) and Coolaroo (COO) to manage overload of SBY under system normal conditions. The annualised cost of expected unserved energy at SBY is forecast to significantly increase from approximately $1.8 million in 2015/16 to $191 million by 2024/25, which is primarily driven by the forecast demand grow resulting in increasing load at risk under system normal conditions. To alleviate emerging constraints at SBY, Jemena identified the following credible network options: Option 1 Augment and redevelop the SBY Zone Substation to current standards by the end of Option 2 Augment and redevelop the SBY Zone Substation to current standards by the end of Develop a new zone substation with two transformers over the period from 2021 to Demolish and handover the existing SBY site in Option 3 Establish a new zone substation by the end of 2018 with the intent of vacating the existing SBY site by Jemena has also undertaken an initial assessment of embedded generation and demand-side management options. The purpose of the Non-Network Options Report is to seek submissions from interested parties, including proponents of non-network solutions, to meet the emerging needs of the Sunbury and Diggers Rest network by providing the relevant technical characteristics, and is available at Jemena s website 11. Jemena has identified Option 1 as the preferred network option. Submissions close on 29 January 2016 and can be provided in writing to Mr Ashely Lloyd, Network Capacity Planning and Assessment Manager, at PlanningRequest@jemena.com.au. Jemena intends to publish Stage Two, the Draft Project Assessment Report, of this RIT-D by 30 June No material impacts on customer connection charges and distribution use of system (DUoS) charges have been identified Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 57

74 5 NETWORK DEVELOPMENT NORTHERN CORRIDOR ELECTRICITY SUPPLY Jemena intends to undertake a RIT-D assessment to fully consider the zone substation and feeder thermal loading risks identified in Jemena s northern corridor supply area. In particular, this will include assessment of the area surrounding Craigieburn, which is currently supplied by zone substations at Somerton (ST), Coolaroo (COO) and Kalkallo (KLO). The RIT-D assessment is expected to commence with publication of the Non- Network Options Report in November METERING AND INFORMATION TECHNOLOGY SYSTEMS METERING AND INFORMATION TECHNOLOGY INVESTMENTS IN 2015 The metering and information technology (IT) capital expenditure plan for 2015 provided $10.2 million of budget for IT projects, which is consistent with completion of the EDPR asset management plan submission, determination and capital expenditure allowances, including: Implement Stage One of a three stage longer-term business intelligence, analytics and data warehouse program from 2015 to Implemented the first of the new Cloud Computing based services using the SAP solutions recently made available in their Australian based data centres. Increased JEN s defences against a long-term increase in security risks and threats maliciously aimed at damaging, disabling and shutting down energy networks. This includes implementing a new Security Information and Event Management system capability along with a 24-hour-a-day, seven-day-a-week security alert monitoring service. This investment is a necessary initiative and major investment beyond what was planned at the time of the JEN EDPR 2011 determination. SAP Financial Management Provides for continuous change to financial management, accounting and reporting as the market and business environment constantly changes. SiteSafe incident management system upgrade. Records and document management development to meet obligations. Retirement of legacy meters (type 4, manually read type 5 and 6, and type 7 metered and unmetered) remaining from the rollout of AMI meters. Piloting new mobility technologies and applications solutions that work with JEN s existing applications. Lifecycle growth and replacement projects for IT Infrastructure will take place for: Data storage. Infrastructure services. Platforms and processing. End user services. Organic growth as the market and business grows. Upon completion of the 2015 program of work, Jemena will have largely delivered the committed EDPR IT program of work. Based on actuals and 2015 estimates, a variance of $3.6 million (5%) is forecast for the period, with the capital expenditure projected at $76.2 million, compared to our allowance of $72.6 million. The actual and estimated annual and total expenditure for the EDPR period is shown 58 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

75 NETWORK DEVELOPMENT 5 in Figure 5 2, alongside our regulatory allowance and revised proposal expenditure, which includes the Merits Review outcomes. Figure 5 2: Actual and forecast IT capital expenditure Metering and information technology investment plan 2016 to 2020 The metering and information technology (IT) program of work for the regulatory period can be summarised to represent the following four themes: Delivering new capabilities to the business that are aligned to market trends and changing industry focus. Improving existing capabilities to minimise risk and drive efficiencies. Enabling business transformation as a key to delivering Jemena s business plan. Responding to business needs in terms of implementing capabilities and enabling solutions that drive regulatory and other priorities. The major projects planned for the regulatory period, listed in Table 5 7, represent a mix of replacement projects and the introduction of new capability for Jemena. The purpose of establishing new system capabilities in JEN is to deliver services and efficiencies in accordance with current benchmarks set by Australian distribution energy businesses and to align Jemena with good industry practice in IT management. Table 5 7: Metering and IT investment summary Project Desktop/Laptop Standard Operating Environment Replacement Customer Relationship Management Investment Description The lifecycle replacement of the devices and standard operating environment at the end of their economic life, for security risk mitigation, at the end of technical life and due to obsolescence. New capability and extend the current customer management services. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 59

76 5 NETWORK DEVELOPMENT Outage Management and Distribution Management Business Analytics Data Warehouse Replacement Project Document and Records Management Geospatial Information Systems Corporate and Field Mobility Standard Control Systems (SCS) metering Network Management System Upgrade AMI Metering contestability Contestable Metering Network Management System Upgrade (Shared system with SCS Metering above IT Infrastructure - Asset Lifecycle Projects Data Storage - SAN Replacement Provision for Growth Provision to Extend, Remediate and Change The upgrade and/or replacement of the current Outage Management System as it reaches end of life. The addition of Distribution Management capability. Capability for outage and phase identification from smart devices on the network. Replace end of life business intelligence technologies, extend capability and leverage the AMI data to improve the energy distribution services through analytics and decision support information. Replace and extend the current AMI Data Warehouse to all of JEN. Archiving and decommissioning of obsolete data and tools Improved capability and safety measures with the addition of new tools and consolidation information through integration with systems sources for asset and image data. New capability that provides devices, network communications and integration to IT systems to support provision of services to customers. This project is a system lifecycle upgrade for a large complex system. New capability to meet new AER regulations and market services to make AMI meters contestable. This project is a system lifecycle upgrade for a system shared with SCS Metering. NB: costs for the contestable metering project will be the subject of a pass-through exercise. Sustain the current capability largely with replacement and some upgrades. Systems replacement at end of life. Part of the IT Infrastructure plan To meet market and business growth for software licenses and capacity growth. Meet demand and plans for greater usage of existing IT systems Improve existing services to be more efficient Remediate systems to ensure sustainable performance standards Respond to continuous external changes made necessary by the market and business environment. Advanced metering infrastructure Advanced metering infrastructure (AMI) is an integrated system of smart meters, communications networks, and data management systems that enable two-way communication between Jemena and our customers. The Victorian Government mandated a full roll out of AMI to small business and residential customers in By 2014, Jemena had successfully completed the deployment of smart meters to 98% of our residential and business customers with a consumption under 160 megawatt-hour per year. 60 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

77 NETWORK DEVELOPMENT 5 While the primary aim of the AMI project was to enable customers to make choices about how much energy they use by allowing them to access accurate real-time information about their electricity consumption, many features of AMI are not yet fully realised that have the potential to provide additional customer benefits, such as: Real-time reports of supply outage and restoration, enabling faster fault detection and restoration. Customer supply quality monitoring, enabling pro-active detection and rectification of degraded service. Direct or indirect load control to support demand-side responses. Improved low voltage asset utilisation through the identification and optimisation of phase loading and load projection. Emergency load limiting to maintain network integrity when discretionary load limiting fails. Customer enabled load limiting. For the 2016 regulatory period, Jemena has sought approval for a trial utilising AMI infrastructure to directly control customer agreed appliances. Jemena also plans to leverage the AMI to further develop a smart network and improve its service delivery to customers, including: Using AMI data (and SCADA data) to analyse the network and develop intelligence and insight for more efficient and effective network management and operation. Deliver network benefits by using AMI, integrated with Jemena s network outage management system to deliver improved operational efficiency, enhanced asset safety, improved supply reliability and quality, and better customer service. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 61

78 5 NETWORK DEVELOPMENT 5.4 DEMAND MANAGEMENT The electricity supply industry, and in particular distribution networks, is undergoing rapid change with the evolution of new technologies that are impacting the way networks are planned, operated and maintained. Customers are increasingly looking for flexible and cost efficient solutions for energy consumption management. Government policy and regulatory frameworks are being formulated to respond to these technology innovations and consumer preferences, and, in line with these changes, Jemena s network investment objective is to provide network services that are safe, affordable and responsive to our customers preferences, while enabling innovation and change. Demand management aims to manage the electricity use profile on a network to minimise the cost of supplying customers while maintaining or improving customer options and service levels, and is defined by the Australian Energy Regulator (AER) 12 as: any effort by a distributor to lower or shift the demand for standard control services, including, agreements between distributors and consumers to switch off loads at certain times and the connection of small-scale 'embedded' generation reducing the demand for power drawn from the distribution network. Non-network solutions that do not involve traditional network asset development (poles and wires) are broadly classified as demand management (DM) solutions and can include: Tariff offerings, such as time of use and critical peak pricing. Demand response, where load reduction is contracted. This load reduction can be initiated by the customer, as directed by the DNSP or in response to price signals, or by the DNSP through direct load control. Embedded generation. Energy storage and subsequent release at peak times, including electric vehicles fitted with vehicle-to-grid technology. Energy efficiency incentive programmes. There are three key drivers for DM program development as an alternative to augmentation works: Investment flexibility. Traditional network investments require large capital expenditure and a long-term commitment to ensure benefits are maximised. In situations where electricity demand is not increasing at the same rate as in the past, or there is uncertainty about future demand growth, DM solutions can provide incremental capacity increases and the flexibility to wait and see how the environment develops, without committing to high cost network developments. Asset development deferral. DM solutions present an opportunity to shift the economic timing of an asset s development. Network constraints can be mitigated or managed at a reduced risk level while still delivering a favourable economic outcome for consumers. Improving network reliability. Distribution Businesses and their customers carry operational risks that can be quantified as the cost of expected unserved energy (EUSE). DM presents an opportunity to mitigate a portion of this power supply risk both before and during outages, thereby reducing the overall costs to consumers and the costs of operating networks. The cost effectiveness of a DM program is driven by the attributes of the customer base and the DM technologies and business processes employed, which must react fast enough to mitigate the impacts of network outages. 12 AER, Final Framework and Approach for the Victorian Electricity Distributors, October 2014, p Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

79 NETWORK DEVELOPMENT DEMAND MANAGEMENT OBJECTIVES AND STRATEGY Jemena s objectives for demand management are to: Develop options and flexibility for our network and customers through the application of DM. Establish policies, systems and processes that support DM. Where economical, resolve network supply quality and capacity constraints using DM. Jemena s strategies to deliver these objectives are to: Establish DM solutions as viable alternatives to traditional network investments, including: Evaluating the feasibility of DM solutions as part of ongoing business as usual planning processes. Implementing DM where economically beneficial to customers and value maximising for Jemena. Collaborating with specialist providers and developing Jemena s intellectual property. Lead the Australian electric utility sector in the successful implementation of DM solutions, including: Assuming a larger role in the demand management value stream and limiting reliance on specialist providers in areas of high strategic priority. Developing resources, systems and processes to maximise the efficiency of Jemena s DM initiatives. Supporting the development of demand management and alternative technology solutions as part of Jemena s growth strategy for its regulated and unregulated businesses. Extend Jemena s demand management capabilities in line with the long term corporate strategy for the business DEMAND MANAGEMENT INITIATIVES In line with Jemena s demand management objectives and strategy, Jemena currently has the following initiatives: Co-development and deployment of a Constraint Analytics Tool (CAT), which is a cloud based market benefits analysis tool that: Performs economic cost-benefit analysis of network and non-network (DM) options. Models, analyses and compares new DM technologies and their economic value. Compares DM solutions at a program level. A production version of the CAT is scheduled for release to Jemena s planning team in late December 2015, and is expected to be integrated into Jemena s 2016 planning processes. Jemena s Energy Portal, which is a demand management initiative designed to enhance the demand management capability of electricity consumers. It uses AMI technology to provide near real-time electricity consumption information allowing consumers to: Know when and how electricity is used in their premises/households. Make an informed decision about their electricity usage in response to price or other parameters. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 63

80 5 NETWORK DEVELOPMENT Review and develop new energy consumption patterns and set targets. A demand response register enables parties to register their interest in being notified of developments relating to distribution network planning and expansion by sending an request to DemandManagement@jemena.com.au. Publication of the Flemington Electricity Supply Non-Network Options Report (section 5.2.1), and the Sunbury-Diggers Rest Electricity Supply Non-Network Options Report (section 5.2.2), both of which provide the relevant technical characteristics to allow interested parties to develop non-network solutions to addresss forecast network constraints. Demand response trial (Phase One), in partnership with a leading demand response aggregator to develop an understating of the benefits, costs, pricing, and commercial and operational structures of targeted demand response programs. For the 2016 regulatory period, the AER has developed a new 'Demand Management and Embedded Generation Connection Incentive Scheme (DMEGCIS), which is largely the same as the scheme used in the 2011 regulatory period with only editorial changes. For the 2016 regulatory period, Jemena has sought approval for the following projects under the DMEGCIS: Efficient connection of micro-embedded generators by maximizing the capacity of low voltage networks for efficient connection of inverter based micro-embedded generators. Direct load control trial utilising the advanced metering infrastructure (AMI) to directly control customer agreed appliances. Managing peak demand through customer engagement by providing education and incentives to empower informed decision making. Technology and economic assessment of residential energy storage by evaluating technical and economic viability of residential scale energy storage solutions when deployed in conjunction with rooftop solar PV systems. Distributed grid energy storage investigating storage solutions to mitigate network capacity constraints and maintain quality of electricity supply. Demand response field trail (Phase Two) - following on from the desktop models developed in 2014, phase two of this trial aims to understand the practical issues associated with dispatch and control of demand responses. Demand Management for Network Project Deferral Jemena has developed a methodology to identify opportunities to defer network augmentation through DM programs. The methodology incorporates a screening process applied to all its capital augmentation projects to identify those projects that have the potential to be deferred on the basis of indicative costs for the following DM options: Demand Response (DR). Mobile generation. Embedded generation (diesel). Solar photovoltaic (PV). Energy storage (batteries). 64 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

81 NETWORK DEVELOPMENT 5 Energy efficiency. The projects where the DM option may be cost effective and were subjected to more detailed analysis include: Flemington Zone Substation electricity supply (see RIT-D description in section 5.2.1). Sunbury Zone Substation electricity supply (see RIT-D description in section 5.2.2). Reconfigure ES kv feeder loads (section 0). Install a new 11 kv HB feeder, HB-21, (see section 0). Although Jemena was not able to justify the deferral of any of these projects following more detailed analysis, we remain committed to developing DM as an alternate to network augmentations and will continue to update and enhance our methodology, particularly given the rapid evolution of technologies available to DM proponents CUSTOMER PROPOSALS In 2015, Jemena has not received any connection enquiries for embedded generators that have a generation capacity greater than 5 MW. Jemena believes this to be a reflection of: The nature of the JEN network, which services the north east of greater metropolitan Melbourne, where there is limited availability of physical space for a significantly sized embedded generator. Underlying weaker energy and maximum demand growth in the Victoria region. A preference for smaller scale embedded generation, particularly roof top solar, for which the JEN network has seen an ongoing increase in installed capacity. Notwithstanding the absence of new connection applications, Jemena will continue to investigate opportunities for embedded generation projects that can reduce network investment while maximising customer benefits. 5.5 FACTORS THAT MAY MATERIALLY IMPACT THE NETWORK This section describes factors that may have a material impact on Jemena s electricity network, including prospective short-circuit levels (fault levels), voltage levels, power system security, quality of supply, and power system reliability and aging and potentially unreliable assets. Fault levels Electrical assets, including switchgear, overhead lines and transformers, have a maximum allowable current rating. When this limit is exceeded under short circuit fault conditions, the assets will be exposed to catastrophic damage and will need to be replaced. Jemena conducts fault level studies to estimate the prospective short-circuit level throughout the network to ensure it is within the capability of network assets and the limits set out in the NER and EDC. Where the regulatory requirements differ, Jemena plans its network to the most onerous standard. The estimated maximum prospective short-circuit level are included in the subsections of Section 5.6 for each of the Jemena owned zone substations. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 65

82 5 NETWORK DEVELOPMENT Table 5 8 shows the maximum allowable short-circuit fault levels (by voltage), as specified in the EDC. Table 5 8: Distribution System Fault Levels Voltage Level (kv) System Fault Level (MVA) Short Circuit Level (ka) < Fault levels are determined by network impedances and power flow. Increasing fault levels on the JEN network are caused by: Network changes at the transmission level, which result in transmission connection point fault level changes that cascade down to the distribution network. Changes to the level of embedded generation. Network changes within our distribution system, such as the installed transformer capacity. For example, a 22 kv network supplied from two 66/22 kv transformers, will experience a higher fault if a third 66/22 kv transformer is installed, due to the change in network impedance. To mitigate against higher fault levels, Jemena would typically operate with open bus ties open fault level on networks where the fault levels would otherwise exceed limits. Alternatively, the addition of network impedance, such as installation of series reactors, will reduce fault levels. Both AW and BD zone substations comprise four 66/22 kv transformers and have their bus ties opened to ensure fault levels remain within the EDC limits. There are no single replacement projects in excess of $2.0 million within the forward planning work program that are driven by fault level issues. To limit the impact of earth fault currents acting as an ignition source in high risk bushfire areas, Jemena is proposing to install Rapid Earth Fault Current Limiters (REFCL) 13, initially at SHM and SBY zone substations in 2017 and 2018 respectively. Voltage Levels All customer equipment requires the supply voltage to remain within allowable bounds in order to function correctly. Jemena is required to maintain customer voltages within specified thresholds, which were discussed in Table 3 4JEN network voltages are affected by: Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

83 NETWORK DEVELOPMENT 5 The amount of generation supplying the JEN network In recent years Jemena has been investigating voltage control challenges posed by increasing penetration of embedded generation systems. In particular, rooftop solar PV systems raise the network voltage at their point of connection to the supply network. Accommodating these voltage rises from a network planning perspective is not trivial, due to the intermittent nature of solar PV generation. With completion of the smart meter rollout program, Jemena now has the capability to monitor the amount of solar PV net generation, as well as the connection point voltages through the smart meter infrastructure. Analysis of the data is ongoing and Jemena is developing proactive measures to address voltage rise issues that are impacting on Jemena s customer voltage supply. Impedance of transmission and distribution network equipment higher impedance equipment, such as long sub-transmission or distribution feeders exhibit a higher voltage drop, or voltage rise if there is generation, across the plant, which is more pronounced during periods of high demand. Load as the demand on the network increases, the network voltages will tend to decrease. Conversely, as the demand on the network decreases, the network voltages will tend to rise. Reactive power demand reactive power is power that is not consumed, but rather, supports network voltages. A customer with a low power factor has a higher reactive power demand. Jemena installs capacitors at its zone substations to supply reactive power demand, and support network voltages. To maintain voltages within the allowable range, Jemena will: Operate the on load tap changer (OLTC) of zone substation or the transmission connection point transformers to lift the customer side voltage, noting that Jemena attempts to optimise the set point for all transformer OLTCs based on the surrounding network characteristics. Add reactive support in the form of capacitor banks, either at zone substations or on pole tops. Install voltage regulators near the end of long feeders that have voltage issues. Although there is no single replacement project in excess of $2.0 million in the forward planning period that is driven by voltage level issues, the following projects will improve the JEN network voltages: Installing 8 MVAR capacitor banks at CS (see Section 5.6.6), BY (see Section 5.6.2), NH (see Section ) and HB (see Section ) zone substations. Installing voltage regulators on feeders SBY-11 and SBY-32 (see Section ). Power system security Power system security refers to the ability to operate the power system in a secure state, such that a contingency event (loss of a network element due to a fault or equipment failure) will not result in cascading loss of supply or immediate overload of network assets that cannot be managed without causing asset damage. Jemena sets its asset limits to ensure power system security, and this is prioritised above power supply. Load transfer or shedding would be implemented, even under system normal conditions, if required to ensure secure operation of the network is achieved at all times. Any expected unserved energy required to ensure power system security would be included in the network risk identification and options analysis. Quality of supply Jemena is required to comply with the requirements in Section 4 of the EDC and Schedule S5.1a of the NER, as discussed in Section 3.5. Poor quality of supply can lead to: Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 67

84 5 NETWORK DEVELOPMENT Increased losses, in the case of unbalance and harmonics. Customer dissatisfaction in the case of voltage variations and flicker, which can result in tripping of sensitive electronic equipment and lighting flicker. Jemena monitors the quality of supply from PQ meters installed throughout its network, at both the zone substation level, and at the far end of one, typically the longest, high voltage distribution feeder emanating from each zone substation. Where quality of supply falls outside allowable limits, or when assessing the impact of new connections, Jemena will carry out system studies investigating power quality, and initiate projects to improve power quality on an as needs basis. There are no single replacement projects in excess of $2.0 million within the forward planning work program that are driven by power quality issues. Power System Reliability / Aging and potentially unreliable assets Power system reliability refers to the capacity of the power system to deliver all customer load. Given that Jemena plans its network to ensure it can meet the forecast demand, aged and deteriorating assets, which are prone to failure, are the primary cause of low power system reliability. Asset failures may reduce service reliability and until the asset is replaced, the security of these services is also reduced, as further failures may result in more widespread service disruptions. Jemena aims to reduce the impact of aging and unreliable assets through its asset management approach, as described in Section 2.2. In the forward planning period, the following network augmentations in excess of $2.0 million include provision for the replacement of aged and unreliable assets. Conversion of the Preston and East Preston area from 6.6 kv to 22 kv. The conversion program of P and EP commenced in 2008 and is planned to be completed in eight stages by around The conversion program upgrades the supply capacity to the area while addressing the 6.6 kv asset condition and reliability. Redeveloping Flemington Zone Substation, as outlined in the Flemington Zone Substation Capacity RIT-D (see section 5.2.1), includes upgrading the aged 11 kv switchgear. While the condition of these assets is not the primary driver of the identified need, replacing these deteriorating assets will help to maintain the long-term reliability levels required for FT s growing demand. Redeveloping Sunbury Zone Substation, as outlined in the Sunbury Diggers-Rest Capacity RIT-D (see section 5.2.2), includes upgrading the 66 kv switchgear and 66/22 kv transformers. While the condition of these assets is not the primary driver of the identified need, replacing these deteriorating assets will help to maintain suitable long-term reliability levels for SBY s growing demand. Fairfield Zone Substation works (see section ) include replacement of the 22/6.6 kv transformers and provision for the future replacement of obsolete and unreliable 6.6 kv switchgear. Footscray East and Footscray West zone substation works, (see sections 0 and ) include the replacement of obsolete and unreliable 22 kv switchgear. North Essendon Zone Substation works (see sections ) include replacement of 22/11 kv transformers, which are aged beyond their nominal life. 68 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

85 NETWORK DEVELOPMENT ZONE SUBSTATION AND FEEDER LINE LIMITATIONS This section presents information about zone substation and feeder line ratings (including potential and proposed risk mitigation options), forecast loading levels for the forward planning period ( ) and the annualised cost of expected unserved energy for identified zone substation limitations. The section also outlines recently completed projects and network developments that Jemena is committed to deliver within the forward planning period. Zone substation limitations Each of the identified zone substation limitations and network impacts incorporate the following annualised information for the forward planning period: A figure showing the 10% probability of exceedence (POE) and 50% POE maximum demand (MD) forecasts, compared to the system normal (N) rating and N-1 rating. The maximum demand forecasts and zone substation ratings presented in these figures are for each zone substation s peak loading period (summer or winter). The 10% POE MD (presented in MVA), during each zone substation s peak demand period for existing and committed zone substations. Power factor at peak load (p.u), being the power factor at the time of peak demand presented in per unit of real to apparent power demand. The value presented assumes that all capacitor banks connected to that zone substation are contributing their full reactive power capability. The 10% POE N-1 loading (%), being the maximum zone substation loading that is forecast to occur during the peak demand period following the worst credible contingency. This loading level is presented as a percentage of the substation s N-1 rating for the peak demand period. Maximum load at risk (MVA), being the load that would be lost if the worst credible outage occurred at the time of peak demand. Hours at risk (h), being the number of hours where the zone substation loading is forecast to exceed the N-1 rating in a given year and is therefore at risk of not being supplied if the worst credible outage occurs. The EUSE (MWh), being the expected unserved energy associated with a network outage in a given year and the probability of that network outage actually occurring (see section for more information). The EUSE is also weighted across two network loading scenarios, with 30% apportioned to risks associated with the 10% POE scenario and 70% apportioned to risks associated with the 50% POE scenario. The cost of EUSE ($ thousand), being the cost of expected unserved energy in a given year (see Section for more information). Embedded generation, being the known amount of large (units above 2 MW) embedded generation connected within the zone substation supply area. Embedded generation has been excluded from the load at risk and expected unserved energy calculations. Load transfer capacity, which is described in detail below. For zone substations where a risk of USE is forecast, Jemena has identified: A selection of mitigation options comprising both network and non-network solutions. An annual maximum possible payment to non-network service providers, which is determined as the annualised capital cost for the preferred network solution, assuming a discount rate of 6.24%, and an assumed asset life of 50 years. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 69

86 5 NETWORK DEVELOPMENT Load transfer capacity Load transfer capacity is the amount of load that can potentially be transferred to adjacent zone substations under emergency outage conditions. System normal load transfer capacities are excluded because any identified transfer capacities resulting in better network supply management would typically occur as a matter of course. Load transfer capacity will typically decrease over time due to reliance on the available capacity of adjoining zone substations and feeder lines, which decrease as network loading increases. Emergency load transfer capabilities have been excluded from the load at risk and expected unserved energy calculations, but are presented to give an indication of the additional support that can potentially be provided under emergency conditions. Feeder line limitations Each zone substation limitation assessment outlines the identified feeder line limitations, with utilisation levels based on 50% POE conditions, and the preferred solutions proposed. Assessing feeder line limitations typically include consideration of the following risk mitigation options: Installing new feeder lines to offload existing heavily loaded feeders. Reconfiguring feeder lines to balance loading between existing feeders and to ensure sufficient transfer capability in the case of a network outage. Thermally uprating existing feeders (or existing feeder sections) to enable them to safely carry more load. Replacing the conductor (or conductor sections) of an existing feeder line with higher capacity conductor to enable it to safely carry more load. Installing embedded generation suitably located in the feeder supply area to offload the existing feeder line. Introducing demand management schemes suitably located in the feeder supply area to voluntarily reduce demand at peak demand times and during network outages. This involves introducing interruptible loads, as negotiated with customers, by offering customer incentives in the form of reduced electricity prices or outage rebates. 70 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

87 NETWORK DEVELOPMENT AIRPORT WEST ZONE SUBSTATION (AW) Background The Airport West Zone Substation (AW) comprises three 66/22 kv 20/30 MVA transformers, one 66/22 kv 20/40 MVA transformer, and three 22 kv buses supplying twelve 22 kv feeder lines. AW supplies the areas of Airport West, Tullamarine, Keilor East and Avondale Heights. Airport West is a critical zone substation that supplies ten of Jemena s high-voltage customers. Following recent relay failures, including ten separate occasions where feeder protection relays failed to operate, Jemena developed a strategy to replace the existing relays to ensure ongoing reliability of supply to its customers. The relay replacement program is planned to be completed by November 2016 and includes establishing a new control building at AW. There is no alternate to replacement, for obsolete protection relays. Due to significant load growth in recent years, and to ensure load relief at AW for the 2016 summer period, commissioning of a new substation Tullamarine Zone Substation (TMA), was completed in For more information about TMA, see Section Substation limits Consistent with the ratings listed in Table 5 9, AW s summer and winter capacities are limited by the 66/22 kv transformer thermal limits. Table 5 9: Airport West Zone Substation ratings Summer Winter Substation N rating MVA MVA Substation N-1 rating MVA MVA Substation fault levels Table 5 10 presents AW s estimated maximum prospective fault levels at the HV and LV buses. Table 5 10: Airport West Zone Substation fault levels Three phase Single phase to ground HV 66 kv 13.7 ka 9.6 ka LV 22 kv 12.4 ka 2.5 ka Network impact Despite strong continued growth in the forecast maximum demand for the AW supply area, following TMA s commissioning this year, load is not expected to be at risk under system normal or N-1 conditions within the forward planning period. Figure 5 3 shows the 10% POE and 50% POE peak (summer) loading forecast (MVA) compared to the substation limits (MVA). Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 71

88 5 NETWORK DEVELOPMENT Figure 5 3: Airport West Zone Substation maximum demand forecast loading Table 5 11 shows the system normal maximum demand forecast, 95% of which is expected to be reached five hours per year, and the power factor at the time of peak load. It also shows the forecast N-1 loading, and that there is no load at risk forecast at AW. Table 5 11: Airport West Zone Substation loading risk and limitation cost % POE MD (MVA) Power factor at peak load (p.u) % POE N-1 loading (%) 84% 83% 86% 89% 92% Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($ thousand) This substation does not have any large embedded generation connected to it but has up to 24.4 MVA of emergency transfer capacity in Risk mitigation options considered There is no forecast load at risk. Proposed preferred solution No further solutions are required. 72 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

89 NETWORK DEVELOPMENT 5 Zone substation feeder limitations With utilisation rates on feeders AW-01, AW-06, AW-07 and AW-11 forecast to reach 116.1%, 95.8%, 86.2% and 79.5% (respectively) by 2020, Jemena is proposing to undertake three network augmentation projects to manage AW feeder loadings during the forward planning period: Reconfigure the AW-06, AW-07 and AW-08 feeders to balance loads across them by November 2017, at an estimated cost of $712 thousand. This project involves: Replacing approximately 1.5 kilometres of overhead conductor with higher capacity 19/3.25 AAC conductor. Installation of three automatic circuit recloser (ACR) devices and one manual gas switch. Reconfiguring the AW-06, AW-07 and AW-08 feeders to balance their loads. This augmentation will also provide sufficient transfer capacity under single contingency conditions within the high voltage network, thereby reducing the overall load at risk during network outage conditions. Without implementation of this option, up to 4.3 MVA of load reduction at AW would be required under outage conditions. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $47 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. Reconfigure the AW-01, AW-03, AW-05 and AW-12 feeders to balance loads across them by November 2018, at an estimated cost of $968 thousand. This project involves: Installation of approximately 350 meters of underground cable. Thermal upgrade of approximately 430 meters of overhead line. Reconfiguring the AW-01, AW-03, AW-05 and AW-12 feeders to balance their loads. Following reconfiguration, load will be balanced between these feeders and there will be sufficient transfer capacity under single contingency conditions for feeder AW-01 and all adjoining feeders. Without implementation of this option, up to 5.5 MVA of load reduction at AW would be required under outage conditions. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $63 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. Reconfigure the AW-03, AW-11 and TMA-22 feeders to balance loads by November 2019, at an estimated cost of $282 thousand. This project involves: Installation of two ACRs. Reconfiguration of the AW-03, AW-11 and TMA-22 feeders to balance loads between these feeders. Without implementation of this option, up to 7.3 MVA of load reduction at AW would be required under outage conditions. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $18 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 73

90 5 NETWORK DEVELOPMENT BRAYBROOK ZONE SUBSTATION (BY) Background Braybrook Zone Substation (BY) comprises one 66/22 kv 20/30 MVA transformer, one 66/22 kv 20/33 MVA transformer and two 22 kv buses supplying five 22 kv feeder lines. BY supplies the areas of Braybrook, Maidstone, Maribyrnong and Footscray. Substation limits Consistent with the ratings listed in Table 5 12, BY s summer and winter capacities are the 66/22 kv transformer thermal limits. Table 5 12: Braybrook Zone Substation ratings Summer Winter Substation N rating 63.0 MVA 63.0 MVA Substation N-1 rating 32.0 MVA 39.6 MVA Substation fault levels Table 5 13 presents BY s estimated maximum prospective fault levels at the HV and LV buses. Table 5 13: Braybrook Zone Substation fault levels Three phase Single phase to ground HV 66 kv 10.5 ka 6.6 ka LV 22 kv 8.6 ka 1.6 ka Network impact The load supplied by the substation under 10% POE and 50% POE summer maximum demand conditions already exceeds the substation s N-1 capacity. Based on the 10% POE summer maximum demand, outage of a 66/22 kv transformer will result in involuntary load shedding of up to 9.0 MVA in With both transformers in service, there is adequate capacity to meet the anticipated maximum demand for the forward planning period. In addition to the identified load at risk, Jemena has also identified a power factor issue that requires attention to ensure it meets the National Electricity Rules requirements. Figure 5 4 shows the 10% POE and 50% POE peak (summer) loading forecast (MVA) compared to the substation limits (MVA). 74 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

91 NETWORK DEVELOPMENT 5 Figure 5 4: Braybrook Zone Substation maximum demand loading Table 5 14 shows the system normal maximum demand forecast, 95% of which is expected to be reached five hours per year, and the power factor at the time of peak demand. It also shows the forecast N-1 loading, maximum load at risk and hours at risk for a network outage, along with the expected unserved energy and the cost of that expected unserved energy. Table 5 14: Braybrook Zone Substation loading risk and limitation cost % POE MD (MVA) Power factor at peak load (p.u) % POE N-1 loading (%) 128% 129% 128% 127% 127% Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($ thousand) The table shows that a load reduction of 9.0 MVA in 2016 would defer any forecast limitation by 12 months, even under N-1 conditions. This substation has no large embedded generation connected to it but has up to 39.5 MVA of emergency transfer capacity in 2015, which can further reduce the impact of a network outage. Risk mitigation options considered Four options have been considered for managing the identified network limitations: Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 75

92 5 NETWORK DEVELOPMENT Option 1: establish two 8 MVAR capacitor banks at BY. The capacitor banks will provide additional capacity at BY, improve the power factor, reduce electrical losses on the sub-transmission lines and power transformers, and defer more costly network augmentations. Option 2: establish a new zone substation in Avondale Heights. This option will provide sufficient capacity to meet anticipated load growth in the Braybrook area to alleviate existing and emerging constraints. Option 3: establish embedded generation suitably located in the BY supply area. Option 4: introduce demand management to voluntarily reduce demand at peak demand times and during network outages. This involves the introduction of interruptible loads (as negotiated with customers) by offering incentives in the form of reduced electricity charges or outage rebates. Proposed preferred solution Jemena is proposing to install two 8 MVAR capacitor banks at BY in November 2018, at an estimated cost of $2.2 million. This option maximises the net economic benefits because it will improve the power factor and reduce electrical losses on the sub-transmission lines and power transformers. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $144 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. Zone substation feeder limitations The average feeder utilisation across the five existing 22 kv feeder lines at BY is low at 45.9% in 2016, and growing to just 46.5% in Despite BY having two 22 kv busses, all five 22 kv feeders are currently connected to the No.1 22 kv bus. A fault on the No.1 22 kv bus will result in loss of supply to all customers currently supplied from BY. To ensure supply security to its customers, Jemena is proposing to undertake one augmentation project at BY within the forward planning period: Reconfigure feeders across the 22 kv BY buses by November 2020, at an estimated cost of $565 thousand. This project involves relocating two existing feeder exits (BY-11 and BY-13) to the BY-21 and BY-22 circuit breakers. After reconfiguration three feeders will be connected to the No.1 22 kv bus at BY, and two will be connected to the No.2 22 kv bus. Designed to improve the reliability of supply to the Braybrook area, if the project did not go ahead, up to 42 MVA of load reduction at BY will occur following outage of the No.1 22 kv bus at BY at the time of maximum demand. It is not expected that a non-network solution could resolve this identified network limitation.. 76 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

93 NETWORK DEVELOPMENT BROADMEADOWS ZONE SUBSTATION (BD) Background Broadmeadows Zone Substation (BD) comprises three 66/22 kv 20/30 MVA transformers, one 66/22 kv 20/33 MVA transformer and three 22 kv buses supplying fourteen 22 kv feeder lines. BD supplies areas of Broadmeadows, Meadow Heights, Jacana and Campbellfield. Following recent relay failures, Jemena developed a strategy to replace the existing relays to ensure ongoing reliability of supply to its customers. The relay replacement program is planned to be completed by November 2017 and includes establishing a new control building at BD. With the closure of Ford s manufacturing plant in Broadmeadows, demand at BD has declined and is forecast to stay relatively flat for the forward planning period. Despite this, many of the feeders supplied from BD remain heavily utilised. To ensure load relief at BD, and on its feeders, from the summer 2016 period onwards, commissioning of a new zone substation, Broadmeadows South (BMS), was completed in For further information on the establishment of BMS, see Section Substation limits Consistent with the ratings listed in Table 5 15, BD s summer and winter capacities are limited by the 66/22 kv transformer thermal limits. Table 5 15: Broadmeadows Zone Substation ratings Summer Winter Substation N rating MVA MVA Substation N-1 rating MVA MVA Substation fault levels Table 5 16: Broadmeadows Zone Substation fault levels presents BD s estimated maximum prospective fault levels at the HV and LV buses. Table 5 16: Broadmeadows Zone Substation fault levels Three phase Single phase to ground HV 66 kv 13.7 ka 8.5 ka LV 22 kv 12.2 ka 2.2 ka Network impact With the commissioning of BMS this year, load is not expected to be at risk at BD under system normal or N-1 conditions within the forward planning period. Figure 5 5 shows the 10% POE and 50% POE peak (summer) loading forecast (MVA) compared to the substation limits (MVA). Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 77

94 5 NETWORK DEVELOPMENT Figure 5 5: Broadmeadows Zone Substation maximum demand loading Table 5 17 shows the system normal maximum demand forecast, 95% of which is expected to be reached eight hours per year, and the power factor at the time of peak demand. It also shows the forecast N-1 loading, maximum load at risk and hours at risk for a network outage, along with the expected unserved energy and the cost of that expected unserved energy. Table 5 17: Broadmeadows Zone Substation loading risk and limitation cost % POE MD (MVA) Power factor at peak load (p.u) % POE N-1 loading (%) 80% 78% 77% 77% 76% Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($ thousand) This substation has 6.4 MW of large embedded generation connected to it and up to 41 MVA of emergency transfer capacity in Risk mitigation options considered There is no forecast load at risk. Proposed preferred solution No solutions are required. 78 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

95 NETWORK DEVELOPMENT 5 Zone substation feeder limitations Following the commissioning of BMS zone substation, the average feeder utilisation across the fourteen BD feeder lines is forecast to reach 51.7% in BD-13 is the heaviest loaded feeder and is forecast to reach 80.4% utilisation by 2016 and 85.7% by Feeders BD-03 and BD-04 have insufficient load transfer capability under single contingency outage conditions and are forecast to reach 72.2% and 71.2% respectively by To ensure supply security to our customers, Jemena is proposing to undertake two feeder augmentation projects at BD within the forward planning period: Reconfigure the BD-03, BD-04 and BMS-21 feeder loads by November 2017, at an estimated cost of $401 thousand. This project involves installing approximately 100 meters of underground cable and 150 meters of new overhead conductor. The works will allow load to be transferred from BD-03 and BD-04 to the lightly loaded BMS-21 feeder. Without implementation of this option, approximately 1.8 MVA of load reduction on BD-04 will be required under outage conditions. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $26 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. Reconfigure the BD-13 feeder loads by November 2017, at an estimated cost of $1.5 million. This project involves installing approximately 1.1 kilometres of underground cable and replacing approximately 1.4 kilometres of overhead line with higher capacity conductor. The works will allow load to be transferred from BD-13 to the upgraded and lightly loaded adjacent feeder. Without implementation of this option, approximately 2.7 MVA of load reduction on BD-13 will be required under system normal conditions. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $98 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 79

96 5 NETWORK DEVELOPMENT BROADMEADOWS SOUTH ZONE SUBSTATION (BMS) Background The Broadmeadows South Zone Substation (BMS) was commissioned in It comprises two 66/22 kv 20/33 MVA transformers and two 22 kv buses, initially supplying five 22 kv feeder lines. BMS supplies the areas of Broadmeadows and Gladstone Park, including approximately 20 MVA of load previously supplied by the Broadmeadows Zone Substation. BMS will not only supply future growth in the Broadmeadows and Gladstone Park areas, but also provides support to neighboring areas of Campbellfield and Coburg. Substation limits Consistent with the ratings listed in Table 5 18, BMS s summer and winter capacities are limited by the 66/22 kv transformer thermal limits. Table 5 18: Broadmeadows South Zone Substation ratings Summer Winter Substation N rating 66.0 MVA 66.0 MVA Substation N-1 rating 38.0 MVA 39.6 MVA Substation fault levels Table 5 19 presents BMS s estimated maximum prospective fault levels at the HV and LV buses. Table 5 19: Broadmeadows South Zone Substation fault levels Three phase Single phase to ground HV 66 kv 12.8 ka 7.9 ka LV 22 kv 8.9 ka 1.7 ka Network impact As a new establishment to offload Broadmeadows Zone Substation, load is not expected to be at risk at BMS under system normal or N-1 conditions within the forward planning period. Figure 5 6 shows the 10% POE and 50% POE peak (summer) loading forecast (MVA) compared to the substation limits (MVA). 80 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

97 NETWORK DEVELOPMENT 5 Figure 5 6: Broadmeadows South Zone Substation maximum demand loading Table 5 20 shows the system normal maximum demand forecast, 95% of which is expected to be reached eight hours per year, and the power factor at the time of peak demand. It also shows the forecast N-1 loading, maximum load at risk and hours at risk for a network outage, along with the expected unserved energy and the cost of that expected unserved energy. Table 5 20: Broadmeadows South Zone Substation loading risk and limitation cost % POE MD (MVA) Power factor at peak load (p.u) % POE N-1 loading (%) 69% 71% 72% 73% 72% Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($ thousand) Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 81

98 5 NETWORK DEVELOPMENT This substation has no large embedded generation connected to it but has up to 39.5 MVA of emergency transfer capacity in 2015, which can further reduce the impact of a network outage. Risk mitigation options considered There is no forecast load at risk. Proposed preferred solution No solutions are required. Zone substation feeder limitations The average feeder utilisation across the five BMS feeder lines is forecast to reach 48.6% in 2016 and 53.3% by Although the backbone of the feeder has sufficient capacity, under network outage conditions a section of feeder BMS-12 is forecast reach 130% loading by 2017 due to a limiting section of conductor. To ensure supply security to our customers, Jemena is proposing to undertake one feeder augmentation project at BMS within the forward planning period: Augment feeder BMS-12 by November 2017, at an estimated cost of $128 thousand. This project involves replacing approximately 500 meters of overhead conductor on feeder BMS-12. This will increase the limiting section s rating from 165 A to 375 A, thereby allowing sufficient transfer capacity for unplanned outages on the adjacent BMS-23 feeder. Without implementation of this option, approximately 1.5 MVA of load reduction on BMS-12 will be required under outage conditions. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $8 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. 82 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

99 NETWORK DEVELOPMENT COBURG NORTH ZONE SUBSTATION (CN) Background Coburg North Zone Substation (CN) comprises two 66/22 kv 20/30 MVA transformers, one 66/22 kv 20/33 MVA transformer, and three 22 kv buses supplying twelve 22 kv feeder lines. CN supplies areas of Coburg North, Fawkner, Reservoir and Preston. Following recent relay failures, Jemena developed a strategy to replace the existing relays to ensure ongoing reliability of supply to its customers. The relay replacement program is planned to be completed by November 2020 and includes establishing a new control building at CN. Substation limits Consistent with the ratings listed in Table 5 21, CN s summer and winter capacities are limited by the 66/22 kv transformer thermal limits. Table 5 21: Coburg North Zone Substation ratings Summer Winter Substation N rating 93.0 MVA 93.0 MVA Substation N-1 rating 72.5 MVA 83.6 MVA Substation fault levels Table 5 22 presents CN s estimated maximum prospective fault levels at the HV and LV buses. Table 5 22: Coburg North Zone Substation fault levels Three phase Single phase to ground HV 66 kv 12.3 ka 7.6 ka LV 22 kv 11.7 ka 2.5 ka Network impact With all transformers in service, and even under N-1 conditions, there is adequate capacity to meet the forecast maximum demand under 10% POE and 50% POE conditions for the forward planning period. Figure 5 7 shows the 10% POE and 50% POE peak (summer) loading forecast (MVA) compared to substation limits (MVA). Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 83

100 5 NETWORK DEVELOPMENT Figure 5 7: Coburg North Zone Substation maximum demand loading Table 5 23 shows the system normal maximum demand forecast, 95% of which is expected to be reached eight hours per year, and the power factor at the time of peak demand. It also shows the forecast N-1 loading, maximum load at risk and hours at risk for a network outage, along with the expected unserved energy and the cost of that expected unserved energy. Table 5 23: Coburg North Zone Substation loading risk and limitation cost % POE MD (MVA) Power factor at peak load (p.u) % POE N-1 loading (%) 89% 91% 91% 91% 90% Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($ thousand) This station has 2.0 MW of large embedded generation connected to it and up to 37.3 MVA of emergency transfer capacity in Risk mitigation options considered There is no forecast load at risk. Proposed preferred solution No solutions are required. 84 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

101 NETWORK DEVELOPMENT 5 Zone substation feeder limitations The average feeder utilisation across the eleven CN feeder lines is forecast to reach 46.6% in 2016, increasing to 49.0 % by With modest utilisation and a relatively flat demand forecast, Jemena is not planning any feeder line augmentations at CN for the forward planning period. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 85

102 5 NETWORK DEVELOPMENT COBURG SOUTH ZONE SUBSTATION (CS) Background Coburg South Zone Substation (CS) consists of two 66/22 kv 20/30 MVA transformers and two 22 kv buses supplying seven 22 kv feeder lines. CS supplies areas of Coburg, Coburg East, Moreland, Pascoe Vale and Pascoe Vale South. Substation limits Consistent with the ratings listed in Table 5 24, CS s summer and winter capacities are limited by the 66/22 kv transformer thermal limits. Table 5 24: Coburg South Zone Substation ratings Summer Winter Substation N rating 60.0 MVA 60.0 MVA Substation N-1 rating 42.2 MVA 47.3 MVA Substation fault levels Table 5 25 presents CS s estimated maximum prospective fault levels at the HV and LV buses. Table 5 25: Coburg South Zone Substation fault levels Three phase Single phase to ground HV 66 kv 11.2 ka 6.7 ka LV 22 kv 8.5 ka 1.6 ka Network impact The load supplied by the substation under 10% POE and 50% POE summer maximum demand conditions already exceeds the substation s N-1 capacity. Based on the 10% POE summer maximum demand, outage of a 66/22 kv transformer will result in involuntary load shedding of up to 13.1 MVA in With both transformers in service, there is adequate capacity to meet the anticipated maximum demand for 10% POE conditions until 2018, and under 50% POE conditions for the forward planning period. Figure 5 8 shows the 10% POE and 50% POE peak (summer) loading forecast (MVA) compared to substation limits (MVA). 86 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

103 NETWORK DEVELOPMENT 5 Figure 5 8: Coburg South Zone Substation maximum demand loading Table 5 26 shows the system normal maximum demand forecast, 95% of which is expected to be reached eight hours per year, and the power factor at the time of peak demand. It also shows the forecast N-1 loading, maximum load at risk and hours at risk for a network outage, along with the expected unserved energy and the cost of that expected unserved energy. Table 5 26: Coburg South Zone Substation loading risk and limitation cost % POE MD (MVA) Power factor at peak load (p.u) % POE N-1 loading (%) 131% 134% 137% 141% 143% Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($ thousand) The table shows that a load reduction of 13.1 MVA in 2016 will defer any forecast limitation by 12 months. This substation has no large embedded generation connected to it but has up to 12.1 MVA of emergency transfer capacity in 2016, which can further reduce the impact of a network outage. Risk mitigation options considered Option 1: install a new 8 MVAR capacitor bank at CS. Option 2: establish a third transformer at CS. This option will alleviate the emerging constraints. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 87

104 5 NETWORK DEVELOPMENT Option 3: establish embedded generation suitably located in the CS supply area. Option 4: introduce demand management to voluntarily reduce demand at peak demand times and during network outages. This involves introducing interruptible loads (as negotiated with customers) by offering incentives in the form of reduced charges or outage rebates. Proposed preferred solution Jemena has identified that Option 1 will maximise the net economic benefit. The new capacitor bank will help provide additional capacity at CS and offload the TTS-CN-CS-TTS 66 kv sub-transmission line loop by improving the power factor and reducing electrical losses on the sub-transmission lines and power transformers. This option will defer more costly network augmentations, and relies on establishing a new Preston Zone Substation (PTN), as part of Stage 6 of the Preston area conversion, by 2018, which will further relieve CS capacity constraints Jemena is proposing to install the new capacitor bank by November 2017, and the project has an estimated cost of $1.0 million. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $67 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. Zone substation feeder limitations The average feeder utilisation across the seven CS feeder lines is forecast to reach 47.2% in 2016 and 56.2% by CS-03, CS-05 and CS-08 are the heaviest loaded feeders and are forecast to reach 86.6%, 77.7% and 80.1% utilisation respectively by To ensure supply security to our customers, Jemena is proposing to undertake two feeder augmentation projects at CS within the forward planning period: Augment feeder CS-05 by November 2017, at an estimated cost of $237 thousand. This project involves replacement of approximately 800 meters of overhead conductor on feeder CS-05. This will increase the feeder rating from 325 A to 375 A, allowing sufficient transfer capacity for unplanned outages on the adjacent CS-02 feeder line. Without implementation of this option, approximately 2.1 MVA of load reduction on CS-05 will be required under outage conditions. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $16 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. Reconfigure CS-02, CS-05 and CS-08 by November 2019, at an estimated cost of $867 thousand. This project involves: Installation of approximately 220 meters of underground cable and 480 meters overhead conductor. Thermally uprating approximately 135 meters of conductor. Installation of one new manual gas switch. 88 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

105 NETWORK DEVELOPMENT 5 The works will allow the lightly loaded CS-09 feeder to offload the heavily loaded CS-05 and CS-08 feeders, and provide sufficient transfer capacity for CS-02. Without implementation of this option, approximately 0.8 MVA of load reduction would be required under system normal conditions, and a further 4.4 MVA of load reduction on CS-08 will be required under outage conditions. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $57 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 89

106 5 NETWORK DEVELOPMENT COOLAROO ZONE SUBSTATION (COO) Background Coolaroo Zone Substation (COO) comprises two 66/22 kv 20/33 MVA transformers and two 22 kv buses supplying six 22 kv feeder lines. COO supplies areas of Coolaroo, Meadow Heights, Greenvale, Roxburgh Park and Oaklands Junction. With some open paddocks within its supply area, COO is at a higher bushfire risk than most of Jemena s supply area. Substation limits Consistent with the ratings presented in Table 5 27, COO s summer and winter capacities are limited by the 66/22 kv transformer thermal limits. Table 5 27: Coolaroo Zone Substation ratings Summer Winter Substation N rating 66.0 MVA 66.0 MVA Substation N-1 rating 38.0 MVA 39.6 MVA Substation fault levels Table 5 28 presents COO s estimated maximum prospective fault levels at the HV and LV buses. Table 5 28: Coolaroo Zone Substation fault levels Three phase Single phase to ground HV 66 kv 12.4 ka 7.3 ka LV 22 kv 8.8 ka 1.7 ka Network impact The load supplied by the substation under 10% POE and 50% POE summer maximum demand conditions already exceeds the substation s N-1 capacity. Based on the 10% POE summer maximum demand, outage of a 66/22 kv transformer will result in involuntary load shedding of up to 9.0 MVA in With both transformers in service, there is adequate capacity to meet the anticipated maximum demand for the forward planning period. Figure 5 9 shows the 10% POE and 50% POE peak (summer) loading forecast (MVA) compared to the substation limits (MVA). 90 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

107 NETWORK DEVELOPMENT 5 Figure 5 9: Coolaroo Zone Substation maximum demand loading Table 5 29 shows the system normal maximum demand forecast, 95% of which is expected to be reached eight hours per year, and the power factor at the time of peak demand. It also shows the forecast N-1 loading, maximum load at risk and hours at risk for a network outage, along with the expected unserved energy and the cost of that expected unserved energy. Table 5 29: Coolaroo Zone Substation loading risk and limitation cost % POE MD (MVA) Power factor at peak load (p.u) % POE N-1 loading (%) 124% 125% 128% 130% 134% Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($ thousand) The table shows that a load reduction of 9.0 MVA in 2016 will defer any forecast limitation by 12 months. This substation does not have any large embedded generation connected to it but has up to 37.3 MVA of emergency transfer capacity in 2016, which can further reduce the impact of a network outage. Risk mitigation options considered Three options have been considered for managing the identified network limitation: Option 1: establish a new zone substation in Craigieburn and transfer some load from COO to Somerton Zone Substation (ST). This option will reduce the risk of overloading assets at COO. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 91

108 5 NETWORK DEVELOPMENT Option 2: establish embedded generation suitably located in the COO supply area. Option 3: introduce demand management to voluntarily reduce demand at peak demand times and during network outages. This involves introducing interruptible loads (as negotiated with customers) by offering incentives in the form of reduced electricity charges or outage rebates. Proposed preferred solution Jemena has identified Option 1 as the proposed preferred solution to alleviate limitations in Jemena s northern growth corridor surrounding Craigieburn, with completion planned by November 2019, and an estimated cost of $21.0 million. This includes land purchase in 2015 and the establishment of four 22 kv feeders from CBN by November This project will alleviate the zone substation limitations at COO in the medium term. For more information about CBN, see Section Jemena is also planning to install a rapid earth fault current limiting (REFCL) device at COO, by November 2020, at an estimated cost of $3.1 million. The REFCL device is designed to limit short circuit levels that occur during a fault, thereby reducing the likelihood of a fault igniting a bushfire. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $1.4 million. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment Zone substation feeder limitations The average feeder utilisation across the six COO feeder lines is forecast to reach 51.9% in 2015 and 58.9% by COO-13 is the heaviest loaded feeder and is forecast to reach 75.5% utilisation by COO-11 is one of the critical feeders supplying the area to the west of Craigieburn, and is forecast to reach 99.1% utilisation by However, it will be offloaded as part of the establishment of CBN and its four new distribution feeders. To ensure supply security to our customers, Jemena is proposing to undertake two feeder augmentation projects at COO within the forward planning period: Install a new COO feeder (COO-23) by November 2018, at an estimated cost of $332 thousand. This project involves installation of approximately 670 meters of underground cable and a new manual gas switch. An existing spare conduit runs the majority of the 670 meter length from the zone substation alongside COO-13 to the required connection point for the new feeder, thereby minimising civil work costs. This option will provide an additional 375 A capacity to the supply area and will offload COO-13. Without implementation of this option approximately 0.3 MVA of load reduction will be required under system normal conditions, and a further 2.7 MVA of load reduction on COO-13 will be required under outage conditions. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $22 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. Establish a tie-line to COO-11 by November 2019, at an estimated cost of $421 thousand. This project will provide back-up supply to radially supplied customers, and involves installing approximately 520 meters of underground cable. Without implementation of this option approximately 200 kva of load reduction on COO- 11 will be required under outage conditions. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $28 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. 92 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

109 NETWORK DEVELOPMENT EAST PRESTON ZONE SUBSTATION (EP) Background East Preston Zone Substation (EP) comprises two 66/6.6 kv 20/27 MVA transformers, two 66/6.6 kv 10/13.5 MVA transformers and six 6.6 kv buses supplying seventeen 6.6 kv feeder lines. The substation is electrically split between two switch houses, EP-A and EP-B. EP supplies areas of Preston, East Preston and Heidelberg West. EP was originally commissioned in 1920s and underwent extensive refurbishment in the 1960s. Due to age and poor condition, many of the substation and distribution assets require replacement over the next five to ten years to maintain acceptable levels of safety and supply reliability. To ensure continued reliability and to avoid inefficient maintenance works and like-for-like replacements of poor condition assets, Jemena developed a strategic plan for conversion of the Preston and East Preston area from 6.6 kv to 22 kv. The conversion program of EP and Preston Zone Substation (P) commenced in 2008 and is planned to be completed in stages by around The program comprises six P conversion stages and eight EP conversion stages. The stages and indicative timings of the conversion are: P Stage 1, EP Stage 1 and EP Stage 2: conversion of P and EP feeders and distribution substations was completed in November P Stage 2: conversion of P feeders and distribution substations was completed in November P Stage 3: conversion of P feeders and distribution substations was completed in December EP Stage 3: establishment of a new East Preston Zone Substation (EPN) on the existing EP site, consisting of one 66/22 kv 20/33 MVA transformer and three new EPN feeders, was completed in November P and EP Stage 4: conversion of P and EP feeders and distribution substations is planned for completion by November P Stage 5: conversion of P feeders and distribution substations is planned for completion by August P Stage 6: decommission P and establish a new Preston Zone Substation (PTN) on the existing site, consisting of two 66/22 kv 20/33 MVA transformers. This stage is planned for completion by November EP Stage 5: conversion of EP feeders and distribution substations is planned for completion by November EP Stage 6: decommissioning of EP-A and installation of a second EPN 66/22 kv 20/33 MVA transformer is planned for completion around EP Stage 7: conversion of EP feeders and distribution substations is planned for completion around EP Stage 8: conversion of EP feeders and distribution substations and decommissioning of EP-B is planned for completion around Substation limits In line with the ratings presented in Table 5 30, the station plant items limiting EP-A s summer and winter capacity is the 66/22 kv transformer thermal limits. Both EP-A and EP-B are operated with an auto-close bus tie circuit breaker, which will close in the event of a transformer outage, which gives a higher N-1 substation rating. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 93

110 5 NETWORK DEVELOPMENT Table 5 30: East Preston-A Zone Substation ratings Summer Winter Substation N rating 22.5 MVA 22.5 MVA Substation N-1 rating 28.5 MVA 28.5 MVA Consistent with the ratings listed in Table 5 31, EP-B s summer and winter capacities are limited by the 6.6 kv transformer circuit breakers and cable thermal limits. Table 5 31: East Preston-B Zone Substation ratings Summer Winter Substation N rating 27.0 MVA 27.0 MVA Substation N-1 rating 28.5 MVA 28.5 MVA Substation fault levels Table 5 32 presents EP-A s estimated maximum prospective fault levels at the HV and LV buses. Table 5 32: East Preston-A Zone Substation fault levels Three phase Single phase to ground HV 66 kv 10.5 ka 8.8 ka LV 6.6 kv 15.9 ka 15.8 ka Table 5 33 presents EP-B s estimated maximum prospective fault levels at the HV and LV buses. Table 5 33: East Preston-B Zone Substation fault levels Three phase Single phase to ground HV 66 kv 10.5 ka 8.8 ka LV 6.6 kv 15.5 ka 15.4 ka Network impact At both EP-A and EP-B, there is adequate capacity to meet the forecast maximum demand under 10% POE and 50% POE conditions for the forward planning period with all transformers in service, and even under N-1 conditions. Figure 5 10 and Figure 5 11 show the 10% POE and 50% POE peak (summer) loading forecast (MVA) compared to the substation limits (MVA) at EP-A and EP-B respectively. 94 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

111 NETWORK DEVELOPMENT 5 Figure 5 10: East Preston-A Zone Substation maximum demand loading Table 5 34 shows the system normal maximum demand forecast for EP-A, 95% of which is expected to be reached four hours per year, and the power factor at the time of peak demand. It also shows the forecast N-1 loading, maximum load at risk and hours at risk for a network outage, along with the expected unserved energy and the cost of that expected unserved energy. Table 5 34: East Preston-A Zone Substation loading risk and limitation cost % POE MD (MVA) Power factor at peak load (p.u) % POE N-1 loading (%) 64% 64% 65% 63% 62% Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($ thousand) Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 95

112 5 NETWORK DEVELOPMENT Figure 5 11: East Preston-B Zone substation maximum demand loading Table 5 35 shows the system normal maximum demand forecast for EP-B, 95% of which is expected to be reached four hours per year, and the power factor at the time of peak demand. It also shows the forecast N-1 loading, maximum load at risk and hours at risk for a network outage, along with the expected unserved energy and the cost of that expected unserved energy. Table 5 35: East Preston-B Zone Substation loading risk and limitation cost % POE MD (MVA) Power factor at peak load (p.u) % POE N-1 loading (%) 50% 51% 51% 50% 49% Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($ thousand) EP-A and EP-B do not have any large embedded generation connected to them. EP-A has up to 8.0 MW of emergency transfer capacity in EP-B has up to 11.9 MVA of emergency transfer capacity in Risk mitigation options considered There is no forecast load at risk. 96 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

113 NETWORK DEVELOPMENT 5 Proposed preferred solution Although no solutions is required to address load at risk, the staged works to upgrade EP-A, EP-B and P zone substations are necessary to maintain acceptable levels of safety and supply reliability. Zone substation feeder limitations The average feeder utilisation across the seventeen EP feeder lines is forecast to reach 54.4% in 2016, decreasing to 54.0% by The relatively flat loading is partially due to load transfers to EPN. With modest utilisation and a relatively flat demand forecast, other than the works associated with the conversion program, Jemena is not planning any feeder line augmentations at EP for the forward planning period. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 97

114 5 NETWORK DEVELOPMENT EAST PRESTON ZONE SUBSTATION (EPN) Background The new East Preston Zone Substation (EPN) was commissioned in 2015 and comprises one 66/22 kv 20/30 MVA transformer and one 22 kv bus supplying three 22 kv feeder lines. Establishing EPN was part of the ongoing strategic plan for conversion of the Preston and East Preston area from 6.6 kv to 22 kv (see Sections and ), to ensure continued reliability and to avoid inefficient maintenance works and like-for-like replacements of poor condition assets. Substation limits In line with the ratings presented in Table 5 36, the station plant items limiting EPN s summer and winter capacity is the 66/22 kv transformer thermal limits. Table 5 36: East Preston Zone Substation ratings Summer Winter Substation N rating 33.0 MVA 33.0 MVA Substation N-1 rating 0.0 MVA 0.0 MVA Substation fault levels Table 5 37 presents EPN s estimated maximum prospective fault levels at the HV and LV buses. Table 5 37: East Preston Zone Substation fault levels Three phase Single phase to ground HV 66 kv 10.0 ka 8.6 ka LV 22 kv 4.9 ka 1.5 ka Network impact At EPN there is adequate capacity to meet the forecast maximum demand under 10% POE and 50% POE conditions for the forward planning period with the transformer in service. However, since EPN is a one transformer zone substation, based on the 10% POE summer maximum demand, outage of the 66/22 kv transformer will result in involuntary load shedding of up to 6.6 MVA in Figure 5 12 shows the 10% POE and 50% POE peak (summer) loading forecast (MVA) compared to the substation limits (MVA) at EPN. 98 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

115 NETWORK DEVELOPMENT 5 Figure 5 12: East Preston Zone Substation maximum demand loading Table 5 38 shows the system normal maximum demand forecast for EPN, 95% of which is expected to be reached four hours per year, and the power factor at the time of peak demand. It also shows the forecast N-1 loading, maximum load at risk and hours at risk for a network outage, along with the expected unserved energy and the cost of that expected unserved energy. Table 5 38: East Preston Zone Substation loading risk and limitation cost % POE MD (MVA) Power factor at peak load (p.u) % POE N-1 loading (%) 0% 0% 0% 0% 0% Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($ thousand) 2, , , , ,686.0 EPN does not have any large embedded generation connected to it. EPN has up to 8.3 MVA of emergency transfer capacity in Risk mitigation options considered Despite the apparently high expected unserved energy forecast at EPN, there is sufficient load transfer capacity to transfer the entire station load under emergency outage conditions. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 99

116 5 NETWORK DEVELOPMENT Proposed preferred solution With the ongoing conversion of zone substations EP and P and sufficient emergency load transfer capacity away from EPN, no further solutions are required at this stage. Zone substation feeder limitations The average feeder utilisation across the three EPN feeder lines is only forecast to reach 18.7% in 2016, increasing to 19.5% by With very modest utilisation and a relatively flat demand forecast, other than the works associated with the EP and P conversion program, Jemena is not planning any feeder line augmentations at EPN for the forward planning period. 100 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

117 NETWORK DEVELOPMENT ESSENDON ZONE SUBSTATION (ES) Background Essendon Zone Substation (ES) comprises two 66/11 kv 20/27 MVA transformers and two 11 kv buses supplying ten 11 kv feeder lines. ES supplies areas of Essendon, Moonee Ponds, Ascot Vale and Niddrie. The existing ES transformers were manufactured in 1965 and due to their age and condition, as confirmed by a paper sample degree of polymerisation (DP) test conducted on the No.1 transformer in 2013, the transformers require replacement within the forward planning period to maintain acceptable levels of supply reliability. The two transformers will be replaced with 66/11 kv 20/33 MVA modern equivalent units. Substation limits Consistent with the ratings in Table 5 39, ES s summer and winter capacities are limited by the 66/11 kv transformer thermal limits. Table 5 39: Essendon Zone Substation ratings Summer Winter Substation N rating 54.0 MVA 54.0 MVA Substation N-1 rating 36.0 MVA 37.3 MVA Substation fault levels Table 5 40 presents ES s estimated maximum prospective fault levels at the HV and LV buses. Table 5 40: Essendon Zone Substation fault levels Three phase Single phase to ground HV 66 kv 11.8 ka 7.8 ka LV 11 kv 13.7 ka 2.0 ka Network impact The load supplied by the substation under 10% POE and 50% POE summer maximum demand conditions already exceeds the substation s N-1 capacity. Based on the 10% POE summer maximum demand, outage of a 66/11 kv transformer will result in involuntary load shedding of up to 7.2 MVA in With both transformers in service, there is adequate capacity to meet the anticipated maximum demand for the forward planning period. Figure 5 13 shows the 10% POE and 50% POE peak (summer) loading forecast (MVA) compared to substation limits (MVA). Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 101

118 5 NETWORK DEVELOPMENT Figure 5 13: Essendon Zone Substation maximum demand loading Table 5 41 shows the system normal maximum demand forecast, 95% of which is expected to be reached five hours per year, and the power factor at the time of peak demand. It also shows the forecast N-1 loading, maximum load at risk and hours at risk for a network outage, along with the expected unserved energy and the cost of that expected unserved energy. Table 5 41: Essendon Zone Substation loading risk and limitation cost % POE MD (MVA) Power factor at peak load (p.u) % POE N-1 loading (%) 120% 120% 120% 118% 116% Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($ thousand) The table shows a load reduction of 7.2 MVA in 2016 will defer any forecast limitation for the forward planning period, even under N-1 conditions. This substation does not have any large embedded generation connected to it but has up to 14.0 MVA of emergency transfer capacity in 2016, which can further reduce the impact of a network outage. Risk mitigation options considered Three options have been considered for managing the identified network limitation: 102 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

119 NETWORK DEVELOPMENT 5 Option 1: Establish a third transformer and a third 11 kv bus at ES. This option will provide sufficient transformer capacity to meet forecast load in the Essendon area, and alleviate the existing constraint. Option 2: Establish embedded generation suitably located in the ES supply area. Option 3: Introduce demand management to voluntarily reduce demand at peak demand times and during network outages. This would involve the introduction of interruptible loads, as negotiated with customers, by offering incentives in the form of reduced electricity charges or outage rebates. Proposed preferred solution Due to the low probability of a transformer failure and since demand is forecast to decrease over the forward planning period, Jemena will continue to monitor load on ES and manage the existing constraint without any further augmentation to the network. Zone substation feeder limitations The average feeder utilisation across the ten ES feeder lines is forecast to reach 58.5% in 2016, reducing to 57.5% in Feeder ES-23 is particularly lightly loaded with forecast utilisation of just 16.6% in 2016 and 15.7% by To ensure supply security to our customers, Jemena is proposing to undertake one feeder augmentation project at ES within the forward planning period. This project will offload ES-15 and ES-24 by increasing loading on the underutilised ES-23 feeder: Reconfigure ES-23 feeder loads by November 2016, at an estimated cost of $2.4 million. This project involves installation of approximately 1.5 kilometres of underground cable, 1.5 kilometres of overhead line and reconfiguration of the ES-15, ES-23 and ES-24 feeder loads. Following reconfiguration, there will be sufficient transfer capacity to meet demand under single contingency conditions. Without implementation of this option approximately 4.5 MVA of load reduction at ES will be required under outage conditions. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $158 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 103

120 5 NETWORK DEVELOPMENT FAIRFIELD ZONE SUBSTATION (FF) Background Fairfield Zone Substation (FF) comprises three 22/6.6 kv 10/13.5 MVA transformers and three 6.6 kv buses supplying six Jemena 6.6 kv feeder lines. The substation also supplies six CitiPower 6.6 kv feeder lines. FF supplies areas of Fairfield, Alphington and Ivanhoe. The existing FF transformers were manufactured in 1955 and due to their age and condition, as confirmed by paper samples taken from the winding leads of the No.1, No.2 and No.3 transformers in 2013 and 2014, the transformers require replacement within the forward planning period to maintain acceptable levels of supply reliability. Much of the distribution substations and network assets within the FF supply area are similarly aged and in a degraded condition requiring replacement. The feeders supplying Jemena s customers in the Fairfield and surrounding areas are highly utilised. Following an outage there is insufficient transfer capacity available to meet forecast demand. Additionally, with the ongoing conversion of its neighbouring zone substations, Preston and East Preston, from 6.6 kv to 22 kv, the FF supply area will soon become an isolated 6.6 kv network. With further expected reductions in the load transfer capacity to adjacent zone substations under outage conditions, the duration of outages is expected to increase significantly in the Fairfield are following completion of the Preston and East Preston conversion program. The Australian Paper Fairfield Zone Substation (APF) was a customer owned zone substation connected at 66 kv and supplied from East Preston Zone Substation (EP). The site was decommissioned in late 2013 and is now in the process of being redeveloped into a multi-level commercial and residential apartment complex, requiring up to 6 MVA of supply in 2017, increasing to 9.3 MVA by Station limits Consistent with the ratings listed in Table 5 42, FF s summer and winter N-1 capacities are limited by a 22 kv overvoltage limit on the 22/6.6 kv transformers. Table 5 42: Fairfield Zone Station Ratings Summer Winter Station N rating 40.5 MVA 40.5 MVA Station N-1 rating 25.7 MVA 31.7 MVA Substation fault levels Table 5 43 presents FF s estimated maximum prospective fault levels at the HV and LV buses. Table 5 43: Fairfield Zone Substation fault levels Three phase Single phase to ground HV 22 kv 7.6 ka 4.2 ka LV 6.6 kv 17.8 ka 2.1 ka Network impact With all transformers in service, and even under N-1 conditions, there is adequate capacity to meet the forecast maximum demand for 10% POE and 50% POE conditions until Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

121 NETWORK DEVELOPMENT 5 Figure 5 14 shows the 10% POE and 50% POE peak (summer) loading forecast (MVA) compared to the substation limits (MVA). Figure 5 14: Fairfield Zone Substation maximum demand loading Table 5 44 shows the system normal maximum demand forecast, 95% of which is expected to be reached five hours per year, and the power factor at the time of peak demand. It also shows the forecast N-1 loading, maximum load at risk and hours at risk for a network outage, along with the expected unserved energy and the cost of that expected unserved energy. Table 5 44: Fairfield Zone Substation loading risk and limitation cost % POE MD (MVA) Power factor at peak load (p.u) % POE N-1 loading (%) 90% 89% 91% 92% 97% Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($ thousand) This substation does not have any large embedded generation connected to it but has up to 1.7 MVA of emergency transfer capacity in 2016, which can further reduce the impact of a network outage. Risk mitigation options considered There is no forecast load at risk until However, there are feeder limitations over the next 5 years, and a number of options have been considered to minimise the whole life cycle cost for the long term need in area. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 105

122 5 NETWORK DEVELOPMENT Six options have been considered for managing the feeder loading and supply area asset condition limitations: Option 1: install three new 6.6 kv feeders (rated at 11 kv) to address forecast feeder loading limitations. Option 2: convert FF feeders from 6.6 kv to 11 kv. Option 3: convert FF feeders from 6.6 kv to 22 kv. Option 4: establish a new zone substation in the Fairfield or Alphington area, to offload FF and its feeders. Option 5: establish embedded generation suitably located in the FF supply area, to offload FF and it feeders. Option 6: introduce demand management to voluntarily reduce demand at peak demand times and during network outages. This involves introducing interruptible loads (as negotiated with customers) by offering incentives in the form of reduced electricity charges or outage rebates. Proposed preferred solution Jemena has identified that Option 1 will defer costly works associated with Jemena s ultimate plan to convert FF to a 22/11 kv zone substation. This option involves installation of three new 6.6 kv feeders (rated at 11 kv to align with Jemena s ultimate plans for FF): One supplying the area to the south of FF, utilising the existing out-of-service APF feeder, by April 2017, at an estimated cost of $439 thousand. One supplying the area to the south-east of FF by November 2017, at an estimated cost of $1.7 million. One supplying the area to the south-west of FF by November 2018, at an estimated cost of $1.3 million. The proposed new feeders from FF will help to supply the new developments planned at the decommissioned APF site and address the risk of overloading the existing 6.6 kv FF feeders. Jemena s ultimate plan is to convert the FF distribution network from 6.6 kv to 11 kv (Option 2). However, this is a longer-term option that will be completed when it is optimally economic to do so, but is likely to be required after the conversion of neighbouring zone substations Preston and East Preston (planned for completion by 2022). Conversion of FF to 11 kv will provide backup feeder capability to the isolated 11 kv network supplied by Heidelberg Zone Substation (HB) and provide the required capacity to meet the existing and forecast demand at FF. Conversion from 6.6 kv to 11 kv will help with the retirement of aged 6.6 kv assets, which are in poor condition and need of replacement. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $226 thousand although a non-network solution would not address the need to retire aged 6.6 kv assets. A non-network solution providing a lower level of capacity than offered by the preferred network solutions would receive a proportionally lower annual payment. Zone substation feeder limitations The average feeder utilisation across Jemena s six FF feeder lines is forecast to reach 68.8% in 2016, increasing to 68.0% in Feeder FF-95 is the heaviest loaded and is forecast to reach 91.1% utilisation in In addition to the feeder works outlined in Option 1 of the zone substation proposed preferred solution, Jemena is proposing to undertake a network performance related feeder project at FF, within the forward planning period: 106 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

123 NETWORK DEVELOPMENT 5 Establish a tie-line to FF-89 by November 2020, at an estimated cost of $1.0 thousand. This project will ensure supply security and reliability to NMIT, and involves installing approximately 990 meters of underground cable. Without implementation of this option approximately 2.5 MVA of load will need to be shed on FF-89 under outage conditions. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $69 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 107

124 5 NETWORK DEVELOPMENT FLEMINGTON ZONE SUBSTATION (FT) Background Flemington Zone Substation (FT) comprises two 66/11 kv 20/30 MVA transformers, two 11 kv buses and ten 11 kv feeder lines. It supplies around 15,000 domestic, commercial and industrial customers in the Flemington, Kensington, Ascot Vale and surrounding areas, with major customers including Flemington Race Course and the Melbourne Showgrounds. FT is a multi-level indoor zone substation that was originally commissioned in the 1960s using air insulated switchgear (AIS). Due to its age and condition, many of the primary assets and the protection and control assets will require replacement over the next five to ten years to maintain acceptable levels of supply reliability. Substation limits The substation plant items limiting FT s summer capacity are the 11 kv transformer cables (23.9 MVA) and the 11 kv transformer circuit breakers and buses (30.5 MVA). Due to these limitations, the existing transformer cyclic ratings (38.4 MVA), cannot be fully utilised under system normal or outage conditions. The summer and winter substation ratings are presented in Table Table 5 45: Flemington Zone Substation ratings Summer Winter Substation N rating 30.5 MVA 30.5 MVA Substation N-1 rating 23.9 MVA 26.3 MVA The existing 11 kv switchboards are near their end-of-life and require replacement to maintain reliable supply. Additionally, all connection points to the 11 kv buses are fully utilised and installation of additional feeder lines to supply the surrounding area is therefore not possible. Substation fault levels Table 5 46 presents FT s estimated maximum prospective fault levels at the HV and LV buses. Table 5 46: Flemington Zone Substation fault levels Three phase Single phase to ground HV 66 kv 16.5 ka 13.1 ka LV 11 kv 14.5 ka 2.7 ka Network impact The load supplied by the substation under 50% POE summer maximum demand conditions already exceeds the substation s system normal and N-1 capacity. Based on the 10% POE summer maximum demand, involuntary load shedding of up to 6.7 MVA in 2016 would be required under system normal conditions. Outage of a 66 kv supply line, 66/11 kv transformer, 11 kv transformer circuit breaker, 11 kv transformer cable or an 11 kv bus, would result in a transformer outage and additional involuntary load shedding of up to 6.6 MVA in 2016, resulting in a total N-1 load at risk of up to 13.3 MVA in MVA of the N-1 load at risk can be managed post-contingent (typically without one hour following an emergency outage) using available load transfer capacity to ES and NS. 108 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

125 NETWORK DEVELOPMENT 5 The worst case outage (failure of a transformer) will result in rotational load shedding until transformer repair or replacement can be achieved. Figure 5 15 shows the 10% POE and 50% POE peak (summer) loading forecast (MVA) compared to the substation limits (MVA). Figure 5 15: Flemington Zone Substation maximum demand forecast loading Table 5 47 shows the system normal maximum demand forecast, 95% of which is expected to be reached six hours per year, and the power factor at the time of peak demand. It also shows the forecast N-1 loading, maximum load at risk and hours at risk for a network outage, along with the expected unserved energy and the cost of that expected unserved energy. The expected unserved energy and the cost of that expected unserved energy includes post-contingent load transfers of 8.7 MVA for each year in the forward planning period, which has reduced the cost of expected unserved energy by approximately 5%. Table 5 47: Flemington Zone Substation loading risk and limitation cost % POE MD (MVA) Power factor at peak load (p.u) % POE N-1 loading (%) 156% 158% 161% 164% 167% Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($ thousand) 2, , , , ,870.1 The table shows that a load reduction of 13.3 MVA in 2016 will defer any forecast limitation by 12 months, even under N-1 conditions. This substation does not have any large embedded generation connected to it but has up to 8.7 MVA of emergency transfer capacity, which has been considered in the limitation cost assessment. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 109

126 5 NETWORK DEVELOPMENT Risk mitigation options considered Jemena commenced a Regulatory Investment Tests for Distribution (RIT-Ds) in 2015 for upgrading FT, and has published a Stage One, the Non-Network Options Report, which is available on its website (see section 5.2.1). Since publication of Stage One of the RIT-D, we have undertaken preliminary design work to firm up the feasibility and deliverability of options. With this preliminary design work, we have also assessed additional options in detail including upgrade of the existing 11 kv transformer cables in the existing cable ducts. The options considered include: Option 1a: upgrade 11 kv transformer cables and 11 kv switchboards, and install a third 11 kv switchboard (in new switch-room building); Option 1b: upgrade 11 kv transformer cables and 11 kv switchboards, and install a third 11 kv switchboard (in existing switch-room building); Option 1c: upgrade 11 kv transformer cables and 11 kv switchboards (in new switch-room building); Option 1d: upgrade 11 kv transformer cables and 11 kv switchboards (in existing switch-room building); Option 2: rebuild Flemington Zone Substation; Option 3: establish a new zone substation to upgrade FT; Option 4: install a third 66/11 kv transformer (in existing switch-room building); Option 5: embedded generation and demand management; Option 6: upgrade 11 kv transformer cables (in existing switch-room building); and Option 7: upgrade 11 kv transformer cables and 11 kv transformer circuit breakers (in existing switch-room building). Proposed preferred solution The preliminary design work undertaken for this network limitation has given us confidence that upgrading the existing 11 kv transformer cables in the existing cable ducts is likely to be possible, although potential deliverability risks still exist. Option 1b maximises the present value of net economic benefit by reducing network outage risks and increasing network capacity to meet forecast demand. This project is planned to be completed by November 2017, at an estimated cost $7.0 million. The development will involve installing three new 11 kv switchboards and installing new, higher rated, 11 kv transformer cables connecting the two existing 66/11 kv transformers to the new 11 kv switchboards. With the upgrade of 11 kv cables in the existing cable ducts likely to be possible, these works are planned to be undertaking in the existing switch-room building, rather than establishing a new building as previously proposed. Following implementation of the proposed preferred option, FT capacity will be limited by the existing 66/11 kv transformers, which each have a cyclic rating of 34.8 MVA, or the upgraded 11 kv transformers cables if significantly higher capacity cables cannot be installed in the existing cable ducts. The proposed network augmentation is expected to provide sufficient capacity to meet the forecast demand under 50% POE N-1 conditions until This residual supply risk will be monitored and managed until replacement of the existing transformers, or installation of a third transformer, is economically justified. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $460 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. 110 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

127 NETWORK DEVELOPMENT 5 Zone substation feeder limitations Due to recent reconfigurations within the Flemington supply area, all feeder lines currently supplied from FT are forecast to remain within their system normal capacity until However, with average feeder loading forecast to reach 68.7% in 2016 and growing to 78.0% by 2020, and with multiple feeders loaded well above these levels, there is insufficient load transfer capacity available under substation or feeder outage conditions. To help manage the existing and forecast supply risk on Flemington feeders, Jemena is proposing to undertake one feeder augmentation during the period, including: Establish a new FT feeder by November 2017, at an estimated cost of $1.7 million. This project involves installation of approximately 1.5 kilometres of underground cable and reconfiguring the FT-02, FT-09 and FT-10 feeders to balance loads between them. Following this reconfiguration there will be sufficient transfer capacity under single contingency conditions to meet demand on FT-02 and all adjoining feeders. Without implementation of this option approximately 0.9 MVA of load reduction at FT will be required under system normal conditions. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $113 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 111

128 5 NETWORK DEVELOPMENT FOOTSCRAY EAST ZONE SUBSTATION (FE) Background Footscray East Zone Substation (FE) comprises one 66/22 kv 20/30 MVA transformer, one 66/22 kv 20/33 MVA transformer and two 22 kv buses supplying five 22 kv feeder lines. FE supplies areas of Footscray, Footscray East, Yarraville and Spotswood. Using our condition based reliability management (CBRM) model, we have also identified thirteen 22 kv circuit breakers that are in poor condition and require replacement. These circuit breakers are aged beyond their expected useable life, have a history of failure, and have deteriorated bushings and mechanism problems. Switchgear replacements at FE are planned for completion by November Substation limits Consistent with ratings listed in Table 5 48, FE s summer and winter N-1 capacities are limited by 22 kv transformer circuit breaker and cable limits. Table 5 48: Footscray East Zone Substation Ratings Summer Winter Substation N rating 63.0 MVA 63.0 MVA Substation N-1 rating 32.0 MVA 39.6 MVA Substation fault levels Table 5 49 presents FE s estimated maximum prospective fault levels at the HV and LV buses. Table 5 49: Footscray East Zone Substation fault levels Three phase Single phase to ground HV 66 kv 14.7 ka 10.4 ka LV 22 kv 9.3 ka 2.2 ka Network impact The load supplied by the substation under 10% POE summer maximum demand conditions already exceeds the substation s N-1 capacity, and the 50% POE summer maximum is also forecast to exceed the substation s N-1 capacity from Based on the 10% POE summer maximum demand, outage of a 66/22 kv transformer would result in involuntary load shedding of up to 3.0 MVA in With both transformers in service, there is adequate capacity to meet the anticipated maximum demand for the forward planning period. Figure 5 16 shows the 10% POE and 50% POE peak (summer) loading forecast (MVA) compared to the substation limits (MVA). 112 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

129 NETWORK DEVELOPMENT 5 Figure 5 16: Footscray East Zone Substation maximum demand loading Table 5 50 shows the system normal maximum demand forecast, 95% of which is expected to be reached six hours per year, and the power factor at the time of peak demand. It also shows the forecast N-1 loading, maximum load at risk and hours at risk for a network outage, along with the expected unserved energy and the cost of that expected unserved energy. Table 5 50: Footscray East Zone Substation loading risk and limitation cost % POE MD (MVA) Power factor at peak load (p.u) % POE N-1 loading (%) 110% 111% 111% 114% 119% Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($ thousand) The table shows a load reduction of 3.0 MVA in 2016 will defer any forecast limitation for 12 months. This substation does not have any large embedded generation connected to it but has up to 27.6 MVA of emergency transfer capacity in 2016, which can further reduce the impact of a network outage. Risk mitigation options considered Two options have been considered for managing the identified network limitation: Option 1: establish embedded generation suitably located in the FE supply area. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 113

130 5 NETWORK DEVELOPMENT Option 2: introduce demand management to voluntarily reduce demand at peak demand times and during network outages. This involves introducing interruptible loads (as negotiated with customers) by offering incentives in the form of reduced electricity charges or outage rebates. Proposed preferred solution Despite some existing load at risk, due to the low probability of a transformer outage concurrent with the peak demand period, there is only a small amount of expected unserved energy each year for the forward planning period. With the load being relatively flat over the next six years, there is insufficient risk to economically justify any network augmentation. Zone substation feeder limitations The average feeder utilisation across the five FE feeder lines is forecast to reach 45.9% in 2016, increasing to 52.0% by With modest utilisation, Jemena is not planning any feeder line augmentations at FE for the forward planning period. 114 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

131 NETWORK DEVELOPMENT FOOTSCRAY WEST ZONE SUBSTATION (FW) Background Footscray West Zone Substation (FW) comprises three 66/22 kv 20/30 MVA transformers and three 22 kv buses supplying eight 22 kv feeder lines. FW supplies areas of Footscray West, Yarraville, Spotswood and Brooklyn. Following recent relay failures, Jemena developed a strategy to replace the existing relays to ensure ongoing reliability of supply to its customers. The relay replacement program is planned to be completed by November There is no alternative to replacement for obsolete protection relays. Using our condition based reliability management (CBRM) model, we have also identified nineteen 22 kv circuit breakers that are in poor condition and require replacement. These circuit breakers are aged beyond their expected useable life, have a history of failure, and have deteriorated bushings and mechanism problems. Switchgear replacements at FW are planned for completion by November Substation limits Consistent with the ratings listed in Table 5 51, FW s summer and winter N-1 capacities are limited by a 66 kv transformer overvoltage limit, a line drop compensation limit and metering limit. Table 5 51: Footscray West Zone Substation Ratings Summer Winter Substation N rating 90.0 MVA 90.0 MVA Substation N-1 rating 70.3 MVA 77.2 MVA Substation fault levels Table 5 52 presents FW s estimated maximum prospective fault levels at the HV and LV buses. Table 5 52: Footscray West Zone Substation fault levels Three phase Single phase to ground HV 66 kv 17.9 ka 14.8 ka LV 22 kv 12.7 ka 3.5 ka Network impact With all transformers in service, and even under N-1 conditions, there is adequate capacity to meet the forecast maximum demand for 10% POE and 50% POE conditions for the forward planning period. Figure 5 17 shows the 10% POE and 50% POE peak (summer) loading forecast (MVA) compared to substation limits (MVA). Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 115

132 5 NETWORK DEVELOPMENT Figure 5 17: Footscray West Zone Substation maximum demand loading Table 5 53 shows the system normal maximum demand forecast, 95% of which is expected to be reached six hours per year, and the power factor at the time of peak demand. It also shows the forecast N-1 loading, maximum load at risk and hours at risk for a network outage, along with the expected unserved energy and the cost of that expected unserved energy. Table 5 53: Footscray West Zone Substation loading risk and limitation cost % POE MD (MVA) Power factor at peak load (p.u) % POE N-1 loading (%) 63% 62% 61% 59% 57% Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($ thousand) This substation does not have any large embedded generation connected to it but has up to 44.9 MVA of emergency transfer capacity in Risk mitigation options considered There is no forecast load at risk. Proposed preferred solution No solutions are required. 116 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

133 NETWORK DEVELOPMENT 5 Zone substation feeder limitations The average feeder utilisation across the eight FW feeder lines is forecast to reach 41.0% in 2016, decreasing to 38.0% by With modest utilisation and declining demand, Jemena is not planning any feeder line augmentations at FW for the forward planning period. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 117

134 5 NETWORK DEVELOPMENT HEIDELBERG ZONE SUBSTATION (HB) Background Heidelberg Zone Substation (HB) comprises two 66/11 kv 20/27 MVA transformers and three 11 kv buses supplying ten 11 kv Jemena feeder lines and one 11 kv AusNet Services feeder line. HB supplies the areas of Heidelberg and Ivanhoe. The existing HB transformers were manufactured in 1966 and due to their age and condition, as confirmed by a paper moisture content and paper sample degree of polymerisation (DP) test conducted on the No.1 transformer in 2013, the transformers require replacement within the forward planning period to maintain acceptable levels of supply reliability. The two transformers will be replaced with 66/11 kv 20/33 MVA modern equivalent units. The transformers replacements are planned for Substation limits Consistent with the ratings listed in Table 5 54, HB s summer and winter N-1 capacities are limited by an overvoltage limit. Table 5 54: Heidelberg Zone Substation Ratings Summer Winter Substation N rating 54.0 MVA 54.0 MVA Substation N-1 rating 29.2 MVA 35.6 MVA Substation fault levels Table 5 55 presents HB s estimated maximum prospective fault levels at the HV and LV buses. Table 5 55: Heidelberg Zone Substation fault levels Three phase Single phase to ground HV 66 kv 8.3 ka 5.6 ka LV 22 kv 12.0 ka 1.6 ka Network impact With all transformers in service, and even under N-1 conditions, there is adequate capacity to meet the forecast maximum demand for 10% POE and 50% POE conditions for the forward planning period. Accordingly, no substation capacity augmentation is planned at HB during the forward planning period. Figure 5 18 shows the 10% POE and 50% POE peak (summer) loading forecast (MVA) compared to the substation limits (MVA). 118 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

135 NETWORK DEVELOPMENT 5 Figure 5 18: Heidelberg Zone Substation maximum demand loading Table 5 56 shows the system normal maximum demand forecast, 95% of which is expected to be reached five hours per year, and the power factor at the time of peak demand. It also shows the forecast N-1 loading, maximum load at risk and hours at risk for a network outage, along with the expected unserved energy and the cost of that expected unserved energy. Table 5 56: Heidelberg Zone Substation loading risk and limitation cost % POE MD (MVA) Power factor at peak load (p.u) % POE N-1 loading (%) 98% 98% 97% 96% 95% Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($ thousand) This substation does not have any large embedded generation or emergency transfer capacity. Risk mitigation options considered There is no forecast load at risk. Proposed preferred solution Although there is no forecast of load at risk at Heidelberg zone substation, Jemena has proposed installing one 8 MVAR capacitor bank at HB by November 2020, at an estimated cost of $1.4 million. This augmentation will Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 119

136 5 NETWORK DEVELOPMENT help provide additional capacity and offload the TSTS-HB-L-Q-TSTS 66 kv sub-transmission line loop by improving the power factor and reducing electrical losses on the sub-transmission lines and power transformers. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $93 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. Zone substation feeder limitations The average feeder utilisation across the seven HB feeder lines is forecast to reach 71.3% in 2016, decreasing to 68.6% in Despite the relatively flat demand, feeders HB-14, HB15 and HB-22 do not have sufficient back-up transfer capacity to meet the forecast demand under outage conditions. Additionally, with its proposed transfer from 6.6 kv to 11 kv, FF will require back-up transfer capacity, particularly during the project development stage. To ensure supply security to our customers, Jemena is proposing to undertake one feeder augmentation project at HB within the forward planning period: Install a new feeder HB feeder (HB-21) by November 2017, at an estimated cost of $2.6 million. This project involves installing approximately 2.8 kilometres of underground cable. Following commissioning of the new HB feeder, there will be sufficient transfer capacity under single contingency conditions for HB14, HB15, HB22 and HB24. The new feeder has the added benefit of providing backup capability for FF to support the conversion program and new developments at the former Australian Paper Fairfield (APF) site. Without implementation of this option approximately 2.2 MVA of load reduction at HB will be required under outage conditions. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $172 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. 120 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

137 NETWORK DEVELOPMENT KALKALLO ZONE SUBSTATION (KLO) Background Kalkallo Zone Substation (KLO) is an AusNet Services owned substation. KLO was constructed by AusNet Services to supply a new industrial park and residential developments in the Merrifield development located along Donnybrook Road. Jemena currently has three feeders in service from KLO, KLO-13, KLO-21 and KLO- 22. KLO-22 leads south of KLO and was established in 2013 to offload the developing residential area to the far north of the Somerton Zone Substation (ST) supply area around Mount Ridley Road. The other two feeders were constructed in 2014 for customers in the Donnybrook road development area. This substation does not have any embedded generation connected to it but has up to 5.4 MVA of emergency load transfer capacity in Zone substation feeder limitations Despite the forecast rapid growth out of KLO, with the establishment of two new customer feeders in 2014, the average feeder utilisation across the three KLO feeder lines is forecast to remain relatively low at 21.7% in 2016, increasing to 35.6% by Feeder KLO-22 is the heaviest loaded feeder with utilisation forecast to increase from 42.4% in 2016 to 49.2% by To ensure supply security to our customers, Jemena is proposing to undertake one network performance feeder project at KLO within the forward planning period: Reconfigure two spurs (radial sections) on KLO-22 by November 2020, at an estimated cost of $544 thousand. This project will provide back-up supply to twelve radially supplied substations, and involves installing approximately 700 meters of underground cable. Without implementation of this project approximately 100 kva of load reduction on KLO-22 will be required under outage conditions. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $36 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 121

138 5 NETWORK DEVELOPMENT NEWPORT ZONE SUBSTATION (NT) Background Newport Zone Substation (NT) comprises two 66/22 kv 35/38 MVA transformers and three 22 kv buses supplying seven 22 kv feeder lines. NT supplies areas of Newport and Williamstown. Substation limits Consistent with the rating listed in Table 5 57, NT s summer and winter capacities are limited by the 66/22 kv transformer thermal limits. Table 5 57: Newport Zone Substation ratings Summer Winter Substation N rating 76.0 MVA 76.0 MVA Substation N-1 rating 41.5 MVA 41.5 MVA Substation fault levels Table 5 58 presents NT s estimated maximum prospective fault levels at the HV and LV buses. Table 5 58: Newport Zone Substation fault levels Three phase Single phase to ground HV 66 kv 14.4 ka 13.5 ka LV 22 kv 12.2 ka 2.0 ka Network impact With all transformers in service, and even under N-1 conditions, there is adequate capacity to meet the forecast maximum demand under 10% POE and 50% POE conditions for the forward planning period. Figure 5 19 shows the 10% POE and 50% POE peak (summer) loading forecast (MVA) compared to the substation limits (MVA). 122 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

139 NETWORK DEVELOPMENT 5 Figure 5 19: Newport Zone Substation maximum demand loading Table 5 59 shows the system normal maximum demand forecast, 95% of which is expected to be reached six hours per year, and the power factor at the time of peak demand. It also shows the forecast N-1 loading, maximum load at risk and hours at risk for a network outage, along with the expected unserved energy and the cost of that expected unserved energy. Table 5 59: Newport Zone Substation loading risk and limitation cost % POE MD (MVA) Power factor at peak load (p.u) % POE N-1 loading (%) 97% 95% 94% 91% 89% Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($ thousand) This substation does not have any large embedded generation connected to it but has up to 7.3 MVA of emergency transfer capacity in Risk mitigation options considered There is no forecast load at risk. Proposed preferred solution No solutions are required. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 123

140 5 NETWORK DEVELOPMENT Zone substation feeder limitations The average feeder utilisation across the seven NT feeder lines is forecast to reach 56.0% in 2016, decreasing to 51.6% by With modest forecast utilisation and declining demand, Jemena is not planning any feeder line augmentations at NT for the forward planning period. 124 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

141 NETWORK DEVELOPMENT NORTH ESSENDON ZONE SUBSTATION (NS) Background North Essendon Zone Substation (NS) comprises three 22/11 kv 10/13.5 MVA transformers and three 11 kv buses supplying nine 11 kv feeder lines. NS supplies the areas of North Essendon, Strathmore, Moonee Ponds and Ascot Vale. The existing NS transformers were manufactured in 1955, and due to their age and condition, as confirmed by paper sample degree of polymerisation (DP) tests conducted on the transformers in 2013, all three existing transformers require replacement within the forward planning period to maintain acceptable levels of supply reliability. Substation limits Consistent with ratings listed in Table 5 60, NS s summer capacity is limited by the 66/11 kv transformer thermal limits. The winter capacity is limited by an overvoltage limit. Table 5 60: North Essendon Zone Substation ratings Summer Winter Substation N rating 40.5 MVA 40.5 MVA Substation N-1 rating 29.6 MVA 29.6 MVA Substation fault levels Table 5 61 presents NS s estimated maximum prospective fault levels at the HV and LV buses. Table 5 61: North Essendon Zone Substation fault levels Three phase Single phase to ground HV 22 kv 5.6 ka 2.5 ka LV 11 kv 9.7 ka 1.6 ka Network impact The load supplied by the substation under 10% POE and 50% POE summer maximum demand conditions already exceeds the substation s N-1 capacity. Based on the 10% POE summer maximum demand, outage of a 22/11 kv transformer will result in involuntary load shedding of up to 6.4 MVA in With both transformers in service, there is adequate capacity to meet the anticipated maximum demand for the forward planning period. Figure 5 20 shows the 10% POE and 50% POE peak (summer) loading forecast (MVA) compared to the substation limits (MVA). Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 125

142 5 NETWORK DEVELOPMENT Figure 5 20: North Essendon Zone Substation maximum demand loading Table 5 62: North Essendon Zone Substation loading risk and limitation cost shows the system normal maximum demand forecast, 95% of which is expected to be reached five hours per year, and the power factor at the time of peak demand. It also shows the forecast N-1 loading, maximum load at risk and hours at risk for a network outage, along with the expected unserved energy and the cost of that expected unserved energy. Table 5 62: North Essendon Zone Substation loading risk and limitation cost % POE MD (MVA) Power factor at peak load (p.u) % POE N-1 loading (%) 122% 121% 122% 123% 125% Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($ thousand) The table shows that a load reduction of 6.4 MVA in 2016 will defer any forecast limitation by 12 months. This substation does not have any large embedded generation connected to it but has up to 11.0 MVA of emergency transfer capacity in 2016, which can further reduce the impact of a network outage. Risk mitigation options considered Five options have been considered for managing the identified network limitation: Option 1: establish a third transformer at Essendon Zone Substation (ES) and transfer some load from NS to ES to reduce the risk of overloading assets at NS. 126 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

143 NETWORK DEVELOPMENT 5 Option 2: replace the existing aged 10/13.5 MVA transformers with modern equivalent, 12/18 MVA, units. Option 3: install two 4 MVAR capacitors to reduce the risk of overloading assets at NS. Option 4: establish embedded generation suitably located in the NS supply area. Option 5: introduce demand management to voluntarily reduce demand at peak demand times and during network outages. This involves introducing interruptible loads (as negotiated with customers) by offering incentives in the form of reduced electricity charges or outage rebates. Proposed preferred solution With only a small amount of expected unserved energy each year, and the forecast demand being relatively flat over the forward planning period, there is insufficient risk to economically justify any significant network augmentation. However, with replacement of the existing transformers planned for November 2017, Jemena has identified that replacement with modern day equivalent units (Option 2) will provide the additional capacity required to mitigate any network limitation within the forecast planning period, while allowing for future demand growth beyond the planning horizon. The modern equivalent transformers will be rated 12/18 MVA, with an incremental cost of approximately $20 thousand per transformer compared to replacement with 10/13.5 MVA units. Zone substation feeder limitations The average feeder utilisation across the nine NS feeder lines is forecast to reach 57.9% in 2016, increasing to 62.0% by With modest utilisation and relatively flat forecast demand, Jemena is not planning any feeder line augmentations at NS for the forward planning period. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 127

144 5 NETWORK DEVELOPMENT NORTH HEIDELBERG ZONE SUBSTATION (NH) Background North Heidelberg Zone Substation (NH) comprises two 66/22 kv 20/30 MVA transformers, one 66/22 kv 20/33 MVA transformer and three 22 kv buses supplying ten 22 kv feeder lines. NH supplies areas of Yallambie, Viewbank, Macleod, Rosanna, Heidelberg Heights and Heidelberg West. Following recent relay failures, Jemena developed a strategy to replace the existing relays to ensure ongoing reliability of supply to its customers. The relay replacement program is planned to be completed by November There is no alternative to replacement for obsolete protection relays. Substation limits Consistent with the ratings listed in Table 5 63, NH s summer and winter capacities are limited by the 66/22 kv transformer thermal limits. Table 5 63: North Heidelberg Zone Substation ratings Summer Winter Substation N rating 93.0 MVA 93.0 MVA Substation N-1 rating 75.2 MVA 76.0 MVA Substation fault levels Table 5 64 presents NH s estimated maximum prospective fault levels at the HV and LV buses. Table 5 64: North Heidelberg Zone Substation fault levels Three phase Single phase to ground HV 66 kv 11.3 ka 6.1 ka LV 22 kv 11.1 ka 2.0 ka Network impact With all transformers in service, and even under N-1 conditions, there is adequate capacity to meet the forecast maximum demand for 10% POE and 50% POE conditions for the forward planning period. Figure 5 21 shows the 10% POE and 50% POE peak (summer) loading forecast (MVA) compared to the substation limits (MVA). 128 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

145 NETWORK DEVELOPMENT 5 Figure 5 21: North Heidelberg Zone Substation maximum demand loading Table 5 65 shows the system normal maximum demand forecast, 95% of which is expected to be reached four hours per year, and the power factor at the time of peak demand. It also shows the forecast N-1 loading, maximum load at risk and hours at risk for a network outage, along with the expected unserved energy and the cost of that expected unserved energy. Table 5 65: North Heidelberg Zone Substation loading risk and limitation cost % POE MD (MVA) Power factor at peak load (p.u) % POE N-1 loading (%) 81% 84% 84% 84% 84% Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($ thousand) This substation has 1.5 MW of large embedded generation connected to it and has up to 17.6 MVA of emergency transfer capacity in Risk mitigation options considered There is no forecast load at risk. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 129

146 5 NETWORK DEVELOPMENT Proposed preferred solution Although there is no forecast of load at risk at North Heidelberg zone substation, Jemena has proposed installing one 8 MVAR capacitor bank at NH by November 2018, at an estimated cost of $1.3 million. This augmentation will help provide additional capacity and offload the TTS-NEI-NH-WT-TTS 66 kv sub-transmission line loop by improving the power factor and reducing electrical losses on the sub-transmission lines and power transformers. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $86 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. Zone substation feeder limitations The average feeder utilisation across the ten NH feeder lines is forecast to reach 53.1% in 2016 and 56.2% in Feeders NH-03 and NH-17 supplying Heidelberg West and its surrounding areas, are heavily loaded with insufficient feeder transfer capacity following a network contingency. Feeders NH-03 and NH-17 are forecast to reach 67.3% and 74.8% utilisation by summer 2020 respectively. To ensure supply security to our customers, Jemena is proposing to undertake one feeder augmentation project at NH within the forward planning period: Install a new feeder line (NH-19) by November 2019, at an estimated cost of $1.6 million. This project involves installing approximately 1.3 kilometres of underground cable and reconfiguring the NH-03, NH-09 and NH-17 feeder loads. Without implementation of this option approximately 1.6 MVA of load reduction between NH-09 and NH-17 will be required under outage conditions. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $103 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. 130 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

147 NETWORK DEVELOPMENT PASCOE VALE ZONE SUBSTATION (PV) Background Pascoe Vale Zone Substation (PV) comprises two 66/11 kv 20/33 MVA transformers, one 66/11 kv 10 MVA and three 11 kv buses supplying nine 11 kv feeder lines. PV supplies areas of Pascoe Vale, Glenroy, Strathmore and Oak Park. Substation limits Consistent with the ratings listed in Table 5 66, PV s summer and winter capacities are limited by the 66/11 kv transformer thermal limits. Table 5 66: Pascoe Vale Zone Substation ratings Summer Winter Substation N rating 64.0 MVA 64.0 MVA Substation N-1 rating 45.6 MVA 45.6 MVA Substation fault levels Table 5 67 presents PV s estimated maximum prospective fault levels at the HV and LV buses. Table 5 67: Pascoe Vale Zone Substation fault levels Three phase Single phase to ground HV 66 kv 11.1 ka 7.1 ka LV 11 kv 12.5 ka 1.6 ka Network impact With all transformers in service, and even under N-1 conditions, there is adequate capacity to meet the forecast maximum demand for 10% POE and 50% POE conditions for the forward planning period. Accordingly, no substation capacity augmentation is planned. Figure 5 22 shows the 10% POE and 50% POE peak (summer) loading forecast (MVA) compared to substation limits (MVA). Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 131

148 5 NETWORK DEVELOPMENT Figure 5 22: Pascoe Vale Zone Substation maximum demand loading Table 5 68 shows the system normal maximum demand forecast, 95% of which is expected to be reached five hours per year, and the power factor at the time of peak demand. It also shows the forecast N-1 loading, maximum load at risk and hours at risk for a network outage, along with the expected unserved energy and the cost of that expected unserved energy. Table 5 68: Pascoe Vale Zone Substation loading risk and limitation cost % POE MD (MVA) Power factor at peak load (p.u) % POE N-1 loading (%) 84% 84% 84% 84% 84% Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($ thousand) This substation does not have any large embedded generation connected to it but has up to 2.4 MVA of emergency transfer capacity in Risk mitigation options considered There is no forecast load at risk. Proposed preferred solution No solutions are required. 132 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

149 NETWORK DEVELOPMENT 5 Zone substation feeder limitations The average feeder utilisation across the nine PV feeder lines is forecast to reach 64.9% in 2016 and 66.5% in Feeders PV-14, PV-22 and PV-31, supplying Glenroy and Strathmore Heights, are forecast to reach 73.3%, 80.0% and 82.3% respectively in Feeder PV-14 only has ties with PV-22 and PV-31, which have insufficient transfer capacity to meet the forecast demand following a network outage. To ensure supply security to our customers, Jemena is proposing to undertake one feeder augmentation project at PV within the forward planning period: Install a new PV feeder line (PV-11) by November 2017, at an estimated cost of $2.6 million. This project involves installing approximately 2.8 kilometres of underground cable, thermally uprating approximately 1.5 kilometres of existing overhead line and reconfiguring the PV-14, PV-22 and PV-31 feeders to balance loads. Following commissioning of PV-11, there will be sufficient transfer capacity under single contingency conditions to supply the forecast demand on PV-14 and its adjoining feeders. Without implementation of this option approximately 5.5 MVA of load reduction at PV will be required under outage conditions. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $168 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 133

150 5 NETWORK DEVELOPMENT PRESTON ZONE SUBSTATION (P) Background Preston Zone Substation (P) comprises two 66/6.6 kv 20 MVA transformer and two 6.6 kv buses supplying five 6.6 kv feeder lines. P supplies areas of Preston. P was originally commissioned in the late 1950s and, due to age and poor condition, many of the substation and distribution assets require replacement over the next five to ten year period to maintain acceptable levels of safety and supply reliability. To ensure continued reliability and to avoid inefficient maintenance works and like-for-like replacements of poor condition assets over the next five to ten years, Jemena developed a strategic plan for the conversion of the Preston and East Preston area from 6.6 kv to 22 kv. The conversion program of P and the East Preston Zone Substation (EP) commenced in 2008 and is planned to be completed in stages by around The program comprises six P conversion stages and eight EP conversion stages. The stages and indicative timings of the conversion are: P Stage 1, EP Stage 1 and Stage 2: conversion of P and EP feeders and distribution substations was completed in November P Stage 2: conversion of P feeders and distribution substations was completed in November P Stage 3: conversion of P feeders and distribution substations was completed in December EP Stage 3: establishment of a new East Preston Zone Substation (EPN) on the existing EP site, consisting of one 66/22 kv 20/33 MVA transformer and three new EPN feeders, was completed in November P and EP Stage 4: conversion of P and EP feeders and distribution substations is planned for completion by November P Stage 5: conversion of P feeders and distribution substations is planned for completion by August P Stage 6: decommission P and establish a new Preston Zone Substation (PTN) on the existing site, consisting of two 66/22 kv 20/33 MVA transformers. This stage is planned for completion by November EP Stage 5: conversion of EP feeders and distribution substations is planned for completion by November EP Stage 6: decommissioning of EP-A and installation of a second EPN 66/22 kv 20/33 MVA transformer is planned for completion around EP Stage 7: conversion of EP feeders and distribution substations is planned for completion around EP Stage 8: conversion of EP feeders and distribution substations and decommissioning of EP-B is planned for completion around Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

151 NETWORK DEVELOPMENT 5 Substation limits Consistent with the ratings listed in Table 5 69, P s summer and winter capacities are limited by the high voltage transformer cables. Table 5 69: Preston Zone Substation ratings Summer Winter Substation N rating 40.0 MVA 40.0 MVA Substation N-1 rating 20.3 MVA 25.3 MVA Substation fault levels Table 5 70 presents P s estimated maximum prospective fault levels at the HV and LV buses. Table 5 70: Preston Zone Substation fault levels Three phase Single phase to ground HV 66 kv 11.1 ka 8.4 ka LV 6.6 kv 21.7 ka 21.9 ka Network impact With all transformers in service, and even under N-1 conditions, there is adequate capacity to meet the forecast maximum demand for 10% POE and 50% POE conditions for the forward planning period. Accordingly, other than conversion program, no further substation capacity augmentation is planned at P during the forward planning period. Figure 5 23 shows the 10% POE and 50% POE peak (summer) loading forecast (MVA) compared to the substation limits (MVA). Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 135

152 5 NETWORK DEVELOPMENT Figure 5 23: Preston Zone Substation Maximum demand loading Table 5 71 shows the system normal maximum demand forecast, 95% of which is expected to be reached four hours per year, and the power factor at the time of peak demand. It also shows the forecast N-1 loading, maximum load at risk and hours at risk for a network outage, along with the expected unserved energy and the cost of that expected unserved energy. Table 5 71: Preston Zone Substation loading risk and limitation cost % POE MD (MVA) Power factor at peak load (p.u) % POE N-1 loading (%) 59% 59% 59% 58% 58% Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($ thousand) This substation does not have any large embedded generation connected to it but has up to 1.2 MVA of emergency transfer capacity in Risk mitigation options considered There is no forecast load at risk. 136 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

153 NETWORK DEVELOPMENT 5 Proposed preferred solution Although no solutions is required to address load at risk, the staged works to upgrade EP-A, EP-B and P zone substations are necessary to maintain acceptable levels of safety and supply reliability. Zone substation feeder limitations The average feeder utilisation across the eight P feeder lines is forecast to reach 41.6% in 2016, increasing to 42.0% by With modest utilisation and a relatively flat demand forecast, other than the works associated with the conversion program, Jemena is not planning any feeder line augmentations at P for the forward planning period. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 137

154 5 NETWORK DEVELOPMENT SOMERTON ZONE SUBSTATION (ST) Background Somerton Zone Substation (ST) is a fully developed substation comprising three 66/22 kv 20/33 MVA transformers and three 22 kv buses supplying twelve 22 kv feeder lines. ST supplies areas of, and surrounding, Somerton, Campbellfield, Craigieburn and Roxburgh Park. As a result of urban sprawl and the recent rezoning of the Urban Growth Boundary, we expect to see continued strong demand growth in the areas currently supplied by ST. As a substation on the urban fringe, the ST supply area is at a higher bushfire risk than most of Jemena s supply area. Substation limits Consistent with the ratings listed in Table 5 72, ST s summer and winter capacities are limited by the 66/22 kv transformer thermal limits. Table 5 72: Somerton Zone Substation Ratings Summer Winter Substation N rating 99.0 MVA 99.0 MVA Substation N-1 rating 79.7 MVA 89.3 MVA Substation fault levels Table 5 73 presents ST s estimated maximum prospective fault levels at the HV and LV buses. Table 5 73: Somerton Zone Substation fault levels Three phase Single phase to ground HV 66 kv 12.3 ka 10.6 ka LV 22 kv 12.0 ka 2.1 ka Network impact With all transformers in service, and even under N-1 conditions, there is adequate capacity to meet the forecast maximum demand for 10% POE and 50% POE conditions until However, due to the strong growth in demand forecast for the ST supply area, outage of a 66/22 kv transformer will result in involuntary load shedding of up to 13.7 MVA by Figure 5 24 shows the 10% POE and 50% POE peak (summer) loading forecast (MVA) compared to substation limits (MVA). 138 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

155 NETWORK DEVELOPMENT 5 Figure 5 24: Somerton Zone Substation Maximum Demand Loading Table 5 74 shows the system normal maximum demand forecast, 95% of which is expected to be reached ten hours per year, and the power factor at the time of peak demand. It also shows the forecast N-1 loading, maximum load at risk and hours at risk for a network outage, along with the expected unserved energy and the cost of that expected unserved energy. Table 5 74: Somerton Zone Substation loading risk and limitation cost % POE MD (MVA) Power factor at peak load (p.u) % POE N-1 loading (%) 99% 102% 107% 112% 117% Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($ thousand) The table shows a load reduction of 2.0 MVA in 2017 would defer any forecast limitation by 12 months. The table indicates that based on the EUSE alone, significant augmentation would not be economically justified in the forward planning period. However, due to the rapid growth in Jemena s northern corridor surrounding Craigieburn, there is forecast to be significant constraints on five high-voltage (HV) feeders supplying the area, including three ST feeders, ST-22, ST-32 and ST-33. In the short term, load at risk on the five critical HV feeders supplying the Craigieburn area will be managed by load transfers to KLO and a feeder reconfiguration planned for completion by November Even with these reconfigurations, it is forecast that in the area surrounding Craigieburn the HV feeders will exceed their capacity by summer Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 139

156 5 NETWORK DEVELOPMENT The three zone substations supplying the northern growth corridor, ST, KLO and COO, are all a significant distance from the current high load growth area, and are forecast to reach capacity within the next ten years. In addition ST, which is the closest supply point, is fully developed with no spare 22 kv circuit breakers available for connection of additional feeders. This substation does not have any large embedded generation connected to it but has up to 30.8 MVA of emergency transfer capacity in 2016, which can further reduce the impact of a network outage. Risk mitigation options considered Six options have been considered for managing the identified network limitation: Option 1: establish a new zone substation in Craigieburn. This option will provide sufficient transformation and distribution capacity to meet anticipated load growth in the Craigieburn and Roxburgh Park areas, to alleviate the emerging constraints. Option 2: establish a new piggyback feeder from ST to defer Craigieburn Zone Substation (CBN) by one year. Option 3: establish a third bus and two new feeder lines from Kalkallo Zone Substation (KLO) to defer the need for CBN by two years. Option 4: establish a third bus and two new KLO feeder lines, as per Option 3, and also establish a third bus and two new feeder lines from Coolaroo Zone Substation (COO), to supply the new load growth areas. Option 5: establish embedded generation suitably located in the ST supply area. Option 6: introduce demand management to voluntarily reduce demand at peak demand times and during network outages. This involves introducing interruptible loads (as negotiated with customers) by offering incentives in the form of reduced electricity charges or outage rebates. Proposed preferred solution Jemena has identified that Option 1 maximises the net economic benefits. This option will alleviate the network limitations identified in the northern growth corridor around Craigieburn. The proposed preferred solution is planned for completion by November 2019, and has an estimated cost of $21.0 million, including the purchase of the land in 2015 and establishment of four 22 kv feeders from CBN, by November Jemena also plans to install a rapid earth fault current limiting (REFCL) device at CBN, by November 2019, at an estimated cost of $2.4 million. The REFCL device is designed to limit short circuit levels that occur during a fault, thereby reducing the likelihood of a fault igniting a bushfire. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $1.4 million. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. Zone substation feeder limitations The average feeder utilisation across the twelve ST feeder lines is forecast to reach 64.4% in 2016 and 57.5% in Despite the relatively low average utilisation levels of ST feeders, there are significant limitations emerging on three critical feeders, ST-22, ST-32 and ST-33. These feeders supply the rapidly developing residential area to 140 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

157 NETWORK DEVELOPMENT 5 the north-west of ST in the Craigieburn, Roxburgh Park and Greenvale areas. It is forecast that by summer 2020 these feeders will have an average utilisation of 107.9%. Jemena plans to alleviate the summer 2016 risk on these feeders by transferring load from ST-32 to Kalkallo feeder, KLO-22. Despite these load transfer plans, there is forecast to be insufficient capacity to meet the demand on ST-32 by summer Additionally, due to forecast demand growth downstream of Craigieburn Road, a section of the ST-22 feeder is also forecast to exceed its rating in summer 2017.To ensure supply security to our customers, Jemena is proposing to undertake one feeder augmentation project at ST within the forward planning period: Reconfigure ST-11 and ST-22 feeder loads by November 2016, at an estimated cost of $1.4 million. This project involves installing a new tie-line between feeders ST-11 and ST-33, replacing an overhead conductor section on ST-22, and reconfiguring ST-11, ST-22, ST-32 and ST-33 feeder loads to balance them across these feeders. Without implementation of this option approximately 2.5 MVA of load reduction on ST-22 will be required under system normal conditions, and a further 2.5 MVA of load reduction will be required under outage conditions. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $89 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. In addition to the feeder augmentation proposed at ST, Jemena is proposing to install four new feeders with the establishment of CBN (by November 2019). These feeders will further offload the heavily loaded ST feeders, as well as offloading heavily loaded feeders supplied from the Coolaroo Zone Substation (COO) and the Kalkallo Zone Substation (KLO), which also supply the Craigieburn area. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 141

158 5 NETWORK DEVELOPMENT SUNBURY ZONE SUBSTATION (SBY) Background Sunbury Zone Substation (SBY) comprises two 66/22 kv 10/16 MVA transformers, one 66/22 kv 10 MVA transformer and three 22 kv buses supplying six 22 kv feeder lines. SBY supplies the areas of Sunbury, Diggers Rest, Bulla, Clarkefield and Gisborne South. When the substation was originally developed, in 1964, it was built with a basic and cost effective switching arrangement that was appropriate for the small and remotely located load that it originally supplied. The site was designed using outdoor switchgear connecting its transformers in a single switching zone. This arrangement is prone to faults caused by wildlife contact, and most faults within the substation will result in a supply interruption to all customers supplied from SBY. In the past twenty years the substation has experienced eighteen faults where all customer demand from the substation was lost due to an asset outage within the transformer switching zone. The SBY supply area has seen strong demand growth in the past ten years and the substation has become much more critical than its original design allowed for. It is now a key switching substation for five subtransmission lines, three of which are owned by Powercor and two by Jemena. As a result of urban sprawl and the recent rezoning of the Urban Growth Boundary we expect to see continued strong demand growth in the areas currently supplied by SBY. As a substation on the urban fringe, the SBY supply area is at a higher bushfire risk than most of Jemena s supply area. Sunbury Zone Substation is built on leased land, with the current lease term set to expire in Substation limits Consistent with the ratings listed in Table 5 75, SBY s summer and winter capacities are limited by the 66/22 kv transformer thermal limits. In particular, the substation s overall system normal rating is limited by the capacity of the 10 MVA transformer, which doesn t allow full utilisation of the 10/16 MVA transformers under system normal conditions due to load sharing. The station is limited during system normal and N-1 conditions. Table 5 75: Sunbury Zone Substation Ratings Summer Winter Substation N rating 32.0 MVA 32.0 MVA Substation N-1 rating 26.4 MVA 26.4 MVA With the zone substation site currently being held under a lease agreement set to expire in 2032, any future investment at the site requires careful consideration to ensure the benefits of the investment can be fully realised. Substation fault levels Table 5 76 presents SBY s estimated maximum prospective fault levels at the HV and LV buses. Table 5 76: Sunbury Zone Substation fault levels Three phase Single phase to ground HV 66 kv 6.9 ka 3.8 ka LV 22 kv 6.3 ka 1.6 ka 142 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

159 NETWORK DEVELOPMENT 5 Network impact The load supplied by the substation under 10% POE and 50% POE summer maximum demand conditions already exceeds the substation s N capacity. Based on the 10% POE summer maximum demand, and in the absence of any operational mitigation action, system normal involuntary load shedding of up to 10.8 MVA in 2016 will be required. Figure 5 25 shows the 10% POE and 50% POE peak (summer) loading forecast (MVA) compared to substation limits (MVA). Figure 5 25: Sunbury Zone Substation maximum demand loading Table 5 77 shows the system normal maximum demand forecast, 95% of which is expected to be reached five hours per year, and the power factor at the time of peak demand. It also shows the forecast N loading, maximum load at risk and hours at risk for system normal conditions, along with the expected unserved energy and the cost of that expected unserved energy. Table 5 77: Sunbury Zone Substation loading risk and limitation cost % POE MD (MVA) Power factor at peak load (p.u) % POE N-1 loading (%) 162% 166% 171% 177% 183% Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($ thousand) 6, , , , ,647.7 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 143

160 5 NETWORK DEVELOPMENT As presented in Table 5 77, a load reduction of 16.4 MVA in 2016 would defer any forecast limitation by 12 months. This substation does not have any large embedded generation connected to it but has up to 9.0 MVA of emergency transfer capacity in 2016, which will continue being used to manage the system normal limitation risk until a long-term solution is implemented. Risk mitigation options considered Five options have been considered for managing the identified network limitation: Option 1: replace the existing 10 MVA transformer with a new 20/33 MVA unit, redevelop SBY with new 66 kv and 22 kv switchgear, and secure long term access to the existing SBY site. Option 2: replace the existing 10 MVA transformer with a new 20/33 MVA unit and redevelop SBY with new 66 kv and 22 kv switchgear, as per Option 1. However, rather than securing long-term access to the existing site, a new zone substation will later be established in the Bulla area, with two 20/33 MVA transformers. SBY will then be decommissioned around 2032, at the end of the current SBY site lease period. Option 3: establish a new zone substation in the Bulla area, with two 20/33 MVA transformers. SBY will be maintained with minimal expenditure and asset replacements until it is decommissioned around 2032, at the end of the current SBY site lease period. Option 4: establish embedded generation suitably located in the SBY supply area. Option 5: introduce demand management to voluntarily reduce demand at peak demand times and during network outages. This involves introducing interruptible loads (as negotiated with customers) by offering incentives in the form of reduced electricity charges or outage rebates. Jemena commenced a Regulatory Investment Tests for Distribution (RIT-Ds) in 2015 for upgrading the Sunbury-Diggers Rest electricity supply, and has published a Stage One, the Non-Network Options Report which is available on its website (see section 5.2.2). Proposed preferred solution Jemena has identified that Option 1 maximises the net economic benefits over the life of the assets. The proposed preferred solution is planned for completion by November 2018, and includes: Purchase of the existing SBY site by 2017, to ensure ongoing access to the site allowing for full utilisation of planned future developments. Installing a rapid earth fault current limiting (REFCL) device at SBY, by November 2017, at an estimated cost of $2.5 million. The REFCL device is designed to limit short circuit levels that occur during a fault, thereby reducing the likelihood of a fault igniting a bushfire. Redevelopment of SBY including replacement of the existing 66 kv and 22 kv switchgear, and replacement of the existing 10 MVA transformer with a 20/33 MVA unit. The substation redevelopment is planned for completion by November 2018, at an estimated cost of $13.2 million. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $868 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. 144 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

161 NETWORK DEVELOPMENT 5 Zone substation feeder limitations The average feeder utilisation across the six SBY feeder lines is forecast to reach 51.8% in 2016, increasing to 60.5% in Feeder SBY-14 is the heaviest loaded feeder with utilisation forecast to increase from 75.1% in 2016 to 81.7% by Despite the relatively low utilisation forecast on most of the feeder lines, there is insufficient back-up transfer capacity between feeders due to the vast area they supply and their geographical remoteness from one another. Many of the feeder lines are also relatively long and suffer from excessive voltage drop. To ensure supply quality and security to our customers, Jemena is proposing to undertake six feeder augmentation projects at SBY within the forward planning period: Augment feeder SBY-14 by November 2017, at an estimated cost of $1.6 million. This project involves replacing almost 9 kilometres of two-wire overhead conductor, installing a third wire to enable conversion of the feeder from two-phase to three-phase supply, and replacing approximately twenty wooden poles. Without implementation of this project approximately 570 kva of load reduction (185 rural customers) on SBY-14 will be required under outage conditions and customers on the longest spur (radial) section of the feeder will suffer poor voltage supply quality. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $102 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. Establish a tie-line between feeders SBY-32 and SBY-11 by November 2017, at an estimated cost of $1.3 million. This project involves installing approximately 600 meters of underground cable and replacing approximately 5.5 kilometres of overhead conductor. Implementation of this project will provide additional transfer capacity under single contingency conditions to supply the forecast load on SBY-32 and SBY-11. Without implementation of this project approximately 1.4 MVA of load reduction at SBY will be required under outage conditions. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $83 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. Establish a new SBY feeder (SBY-12) by November 2017, at an estimated cost of $1.5 million. This project involves installing approximately 2 kilometres of overhead line, 1 kilometre of underground cable, and reconfiguration of SBY-14 feeder loads. Following commissioning of the new SBY feeder, there will be sufficient transfer capacity under single contingency conditions to supply the forecast load on SBY-14 and its adjoining feeders. Without implementation of this project approximately 8.7 MVA of load reduction on SBY-14 will be required under outage conditions. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $96 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. Augment feeder SBY-32 by November 2018, at an estimated cost of $1.3 million. This project involves replacing approximately 650 meters of underground cable, replacing approximately 7.7 kilometres of twowire overhead conductor, and installing a third overhead conductor to allow conversion to three-phase supply. Following completion of this project, the line rating will increase from 28 A two-phase, to 109 A three-phase. Without implementation of this project approximately 370 kva of load reduction on SBY-32 will be required under system normal conditions. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 145

162 5 NETWORK DEVELOPMENT An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $82 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. Install a voltage regulator on SBY-11 by November 2018, at an estimated cost of $231 thousand. This project involves installing a three-phase 50 A 32-step +/-10% voltage regulator near the corner of Riddell Rd and Settlement Rd, and adjustment of transformer tap settings. Installing the voltage regulator will help to boost the end-of-feeder customer voltage level back to acceptable levels as defied in the Victorian Electricity Distribution Code. Without implementation of this project, customers near the end of the feeder will suffer poor supply quality. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $15 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. Install a voltage regulator on feeder SBY-32 by November 2020, at an estimated cost of $250 thousand. This project involves installing a three-phase 50 A 32-step +/-10% voltage regulator near the corner of Couangalt Rd and McGeorge Rd, and adjustment of transformer tap settings. Installing the voltage regulator will help to boost the end-of-feeder customer voltage level back to acceptable levels as defined in the Victorian Electricity Distribution Code. Without implementation of this project, customers near the end of the feeder will suffer poor supply quality. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $16 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. 146 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

163 NETWORK DEVELOPMENT SYDENHAM ZONE SUBSTATION (SHM) Background Sydenham Zone Substation (SHM) comprises two 66/22 kv 20/33 MVA transformers and two 22 kv buses supplying five 22 kv feeder lines. SHM supplies areas of Sydenham, Hillside and Taylors Lakes. With some open paddocks and rural areas within its supply area, SHM is at a higher bushfire risk than most of Jemena s supply area. Substation limits Consistent with the ratings listed in Table 5 78, SHM s summer and winter capacities are limited by the 66/22 kv transformer thermal limits. Table 5 78: Sydenham Zone Substation ratings Summer Winter Substation N rating 66.0 MVA 66.0 MVA Substation N-1 rating 38.0 MVA 39.6 MVA Substation fault levels Table 5 79 presents SHM s estimated maximum prospective fault levels at the HV and LV buses. Table 5 79: Sydenham Zone Substation fault levels Three phase Single phase to ground HV 66 kv 7.1 ka 4.0 ka LV 22 kv 7.5 ka 1.7 ka Network impact The load supplied by the substation under 10% POE summer maximum demand conditions already exceeds the substation s N-1 capacity, and the 50% POE summer maximum demand is forecast to exceed the substations N-1 capacity by Based on the 10% POE summer maximum demand, outage of a 66/22 kv transformer would result in involuntary load shedding of up to 3.1 MVA in 2016, increasing to 6.8 MVA by With both transformers in service, there is adequate capacity to meet the anticipated maximum demand for the forward planning period. Figure 5 26 shows the 10% POE and 50% POE peak (summer) loading forecast (MVA) compared to the substation limits (MVA). Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 147

164 5 NETWORK DEVELOPMENT Figure 5 26: Sydenham Zone Substation maximum demand loading Table 5 80 shows the system normal maximum demand forecast, 95% of which is expected to be reached five hours per year, and the power factor at the time of peak demand. It also shows the forecast N-1 loading, maximum load at risk and hours at risk for a network outage, along with the expected unserved energy and the cost of that expected unserved energy. Table 5 80: Sydenham Zone Substation loading risk and limitation cost % POE MD (MVA) Power factor at peak load (p.u) % POE N-1 loading (%) 108% 109% 112% 115% 118% Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($ thousand) The table shows that a load reduction of 3.1 MVA in 2016 will defer any forecast limitation by 12 months. This substation does not have any large embedded generation connected to it but has up to 1.9 MVA of emergency transfer capacity in 2016, which can further reduce the impact of a network outage. Risk mitigation options considered Four options have been considered for managing the identified network limitation: 148 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

165 NETWORK DEVELOPMENT 5 Option 1: establish a new zone substation in Plumpton (PLN). This option will provide sufficient transformation and distribution capacity to meet anticipated load growth in the Plumpton area, to alleviate the emerging limitations. Option 2: install a new (third) 66/22 kv 20/33 MVA transformer at SHM. Option 3: establish embedded generation suitably located in the SHM supply area. Option 4: introduce demand management to voluntarily reduce demand at peak demand times and during network outages. This involves introducing interruptible loads (as negotiated with customers) by offering incentives in the form of reduced electricity charges or outage rebates. Proposed preferred solution Jemena has identified that Option 1 maximises the net economic benefits over the life of the assets. Due to its proximity to the high load growth area, a new zone substation in the Plumpton area will reduce high voltage feeder and distribution asset costs, compared to expansion of SHM which was ultimately designed as a two transformer zone substation. Jemena will continue monitoring the loading on SHM and its feeder lines to identify the optimal timing for establishment of PLN, which is currently estimated at approximately 2025 based on existing demand forecasts. In the meantime, Jemena is proposing to identify and purchase a land parcel in the Plumpton area that is suitable for development of a new zone substation by December 2020, at an estimated cost of $2.0 million. Due to SHM being in a higher bushfire risk area than most of Jemena s network, Jemena is also proposing to install a rapid earth fault current limiting (REFCL) device at SHM, by November 2016, at an estimated cost of $1.8 million. The REFCL device is designed to limit short circuit levels that occur during a fault, reducing the likelihood of a fault igniting a bushfire. Zone substation feeder limitations The average feeder utilisation across the five SHM feeder lines is forecast to reach 58.2% in 2016, increasing to 66.3% by Feeders SHM-14 and SHM-22 are the most heavily loaded with utilisation forecast to reach 76.2% and 88.5% respectively in 2016 and 89.8% and 93.2 by With the heavy utilisation levels forecast on these two feeders, there is insufficient back-up transfer capacity between them to supply the forecast demand following a network outage. To ensure supply security to our customers, Jemena is proposing to undertake one feeder augmentation project at SHM within the forward planning period: Install a new SHM feeder (SHM-22) by November 2016, at an estimated cost of $902 thousand. This project involves installation of approximately 1.7 kilometres of underground cable and reconfiguration of feeders SHM-14 and SHM-21. Following commissioning of the new SHM feeder, there will be sufficient transfer capacity under single contingency conditions to supply the forecast demand on SHM-14 and its adjoining feeders. Without implementation of this project approximately 8.7 MVA of load reduction at SHM will be required under outage conditions. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $59 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 149

166 5 NETWORK DEVELOPMENT THOMASTOWN ZONE SUBSTATION (TT) Background Thomastown Zone Substation (TT) is an AusNet Services owned substation that supplies four 22 kv Jemena feeder lines, TT-03, TT-08, TT-10 and TT-11. This substation has 3.0 MVA of embedded generation connected to it and up to 14.7 MVA of emergency transfer capacity in Zone substation feeder limitations The average feeder utilisation across the four TT feeder lines is forecast to reach 68.7% in 2016, increasing to 70.6% by Feeder TT-08 is the heaviest loaded with utilisation forecast to reach 77.6% by With the heavy utilisation levels forecast on this feeder, there is insufficient back-up transfer capacity to supply the forecast demand following a network outage. To ensure supply security to our customers, Jemena is proposing to undertake one feeder augmentation project at TT within the forward planning period: Augment feeder TT-10 by November 2020, at an estimated cost of $540 thousand. This project involves replacing approximately 1.6 kilometres of overhead conductor on feeder TT-10. This will increase the feeder rating from 325 A to 375 A, allowing sufficient transfer capacity for unplanned outages on the adjacent feeder, TT-08. Without implementation of this project approximately 3.6 MVA of load reduction on TT-10 will be required under outage conditions. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $35 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. 150 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

167 NETWORK DEVELOPMENT TOTTENHAM ZONE SUBSTATION (TH) Background Tottenham Zone Substation (TH) comprises two 66/22 kv 30/45 MVA transformers and two 22 kv buses supplying five 22 kv feeder lines. TH supplies areas of Tottenham and Brooklyn. Substation limits Consistent with the ratings listed in Table 5 81, TH s summer and winter N-1 capacities are limited by cable thermal limits. Table 5 81: Tottenham Zone Substation ratings Summer Winter Substation N rating 90.0 MVA 90.0 MVA Substation N-1 rating 49.5 MVA 50.1 MVA Substation fault levels Table 5 82 presents TT s estimated maximum prospective fault levels at the HV and LV buses. Table 5 82: Tottenham Zone Substation fault levels Three phase Single phase to ground HV 66 kv 16.4 ka 13.0 ka LV 22 kv 9.3 ka 2.0 ka Network impact With all transformers in service, and even under N-1 conditions, there is adequate capacity to meet the forecast maximum demand for 10% POE and 50% POE conditions for the forward planning period. Accordingly, no substation capacity augmentation is planned at TH during the forward planning period. Figure 5 27 shows the 10% POE and 50% POE peak (summer) loading forecast (MVA) compared to the substation limits (MVA). Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 151

168 5 NETWORK DEVELOPMENT Figure 5 27: Tottenham Zone Substation maximum demand loading Table 5 83 shows the system normal maximum demand forecast, 95% of which is expected to be reached six hours per year, and the power factor at the time of peak demand. It also shows the forecast N-1 loading, maximum load at risk and hours at risk for a network outage, along with the expected unserved energy and the cost of that expected unserved energy. Table 5 83: Tottenham Zone Substation loading risk and limitation cost % POE MD (MVA) Power factor at peak load (p.u) % POE N-1 loading (%) 56% 55% 53% 52% 51% Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($ thousand) This substation has 3.0 MW of large embedded generation connected to it and up to 26.6 MVA of emergency transfer capacity in Risk mitigation options considered There is no forecast load at risk. Proposed preferred solution No solutions are required. 152 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

169 NETWORK DEVELOPMENT 5 Zone substation feeder limitations The average feeder utilisation across the five TH feeder lines is forecast to reach 34.7% in 2016, decreasing to 31.7% by Feeder TH-21 is the most heavily loaded with utilisation forecast to reach 117.6% in 2016, decreasing to 104.3% by Despite the heavy loading on TH-21, Jemena is not planning any feeder line augmentations at TH. This is due to the forecast decline in demand, sufficient load transfer capacity away from TH-21, and the short peaky nature of the traction load connected to TH-21, which is not expected to remain high long enough for the expected overload to damage the conductor or result in unsafe operation of the conductor. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 153

170 5 NETWORK DEVELOPMENT TULLAMARINE ZONE SUBSTATION (TMA) Background Tullamarine Zone Substation (TMA) was commissioned in 2015 and comprises two 66/22 kv 20/33 MVA transformers and two 22 kv buses supplying five 22 kv feeder lines. TMA supplies areas of Tullamarine and Keilor Park, including approximately 20 MVA of load previously supplied by Airport West Zone Substation. TMA will not only supply future growth in Tullamarine and Keilor Park, but also provides support to neighbouring areas of Airport West and Melbourne Airport. Substation limits Consistent with the ratings listed in Table 5 84, TMA s summer and winter capacities will be limited by 66/22 kv transformer thermal limits. Table 5 84: Tullamarine Zone Substation ratings Summer Winter Substation N rating 66.0 MVA 66.0 MVA Substation N-1 rating 38.0 MVA 39.6 MVA Substation fault levels Table 5 85 presents TMA s estimated maximum prospective fault levels at the HV and LV buses. Table 5 85: Tullamarine Zone Substation fault levels Three phase Single phase to ground HV 66 kv 12.8 ka 8.6 ka LV 22 kv 8.7 ka 1.6 ka Network impact With both transformers in service, and even under N-1 conditions, there is adequate capacity to meet the forecast maximum demand for 10% POE and 50% POE conditions for the forward planning period. Accordingly, no substation capacity augmentation is planned at TMA during the forward planning period. Figure 5 28 shows the 10% POE and 50% POE peak (summer) loading forecast (MVA) compared to the substation limits (MVA). 154 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

171 NETWORK DEVELOPMENT 5 Figure 5 28: Tullamarine Zone Substation maximum demand loading Table 5 86 shows the system normal maximum demand forecast, 95% of which is expected to be reached five hours per year, and the power factor at the time of peak demand. It also shows the forecast N-1 loading, maximum load at risk and hours at risk for a network outage, along with the expected unserved energy and the cost of that expected unserved energy. Table 5 86: Tullamarine Zone Substation loading risk and limitation cost % POE MD (MVA) Power factor at peak load (p.u) % POE N-1 loading (%) 63% 71% 74% 77% 80% Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($ thousand) This substation has no large embedded generation connected to it but has up to 22.7 MVA of emergency transfer capacity in Risk mitigation options considered There is no forecast load at risk. Proposed preferred solution No solutions are required. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 155

172 5 NETWORK DEVELOPMENT Zone substation feeder limitations The average feeder utilisation across the five TMA feeder lines is forecast to reach 35.8% in 2016, increasing to 48.2% by None of these feeder lines are forecast to reach their capacity within the forward planning period. However, to offload feeder lines at AW, Jemena is proposing to reconfigure the AW-03, AW-11 and TMA-22 feeder loads by November 2019, at an estimated cost of $282 thousand. This project involves installing two ACRs and reconfiguring the AW-03, AW-11 and TMA-22 feeders to balance loads between these feeders. Without implementation of this option, up to 7.3 MVA of load reduction at AW will be required under outage conditions. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $18 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. 156 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

173 NETWORK DEVELOPMENT WATSONIA ZONE SUBSTATION (WT) Background Watsonia Zone Substation (WT) is an AusNet Services owned substation that supplies one 22 kv Jemena feeder line, WT-04. Feeder WT-04 supplies the Watsonia area, including the Simpsons Army Barracks, and has ties with the North Heidelberg Zone Substation (NH). This substation does not have any embedded generation connected to it but has up to 2.9 MVA of emergency transfer capacity in Zone substation feeder limitations Feeder WT-04 has a forecast utilisation of 27.2% in 2016, increasing to 44.0% by Due to the relatively light loading forecast on WT-04, no feeder augmentation works are proposed within the forward planning period. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 157

174 5 NETWORK DEVELOPMENT YARRAVILLE ZONE SUBSTATION (YVE) Background Yarraville Zone Substation (YVE) comprises two 66/22 kv 20/33 MVA transformers and two 22 kv buses supplying nine 22 kv feeder lines. YVE supplies areas of Yarraville, Spotswood and Maribyrnong. Substation limits Consistent with the ratings listed in Table 5 87, YVE s summer and winter capacities are limited by the 66/22 kv transformer thermal limits. Table 5 87: Yarraville Zone Substation ratings Summer Winter Substation N rating 66.0 MVA 66.0 MVA Substation N-1 rating 38.0 MVA 39.6 MVA Substation fault levels Table 5 88 presents YVE s estimated maximum prospective fault levels at the HV and LV buses. Table 5 88: Yarraville Zone Substation fault levels Three phase Single phase to ground HV 66 kv 14.3 ka 12.3 ka LV 22 kv 9.3 ka 1.6 ka Network impact With all transformers in service, and even under N-1 conditions, there is adequate capacity to meet the forecast maximum demand for 10% POE and 50% POE conditions for the forward planning period. Accordingly, no substation capacity augmentation is planned at YVE during the forward planning period. Figure 5 29 shows the 10% POE and 50% POE peak (summer) loading forecast (MVA) compared to the substation limits (MVA). 158 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

175 NETWORK DEVELOPMENT 5 Figure 5 29: Yarraville Zone Substation maximum demand loading Table 5 89 shows the system normal maximum demand forecast, 95% of which is expected to be reached six hours per year, and the power factor at the time of peak demand. It also shows the forecast N-1 loading, maximum load at risk and hours at risk for a network outage, along with the expected unserved energy and the cost of that expected unserved energy. Table 5 89: Yarraville Zone Substation loading risk and limitation cost % POE MD (MVA) Power factor at peak load (p.u) % POE N-1 loading (%) 83% 86% 88% 89% 89% Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($ thousand) This substation does not have any large embedded generation connected to it but has up to 16.0 MVA of emergency transfer capacity in Risk mitigation options considered There is no forecast load at risk. Proposed preferred solution No solutions are required. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 159

176 5 NETWORK DEVELOPMENT Zone substation feeder limitations The average feeder utilisation across the nine YVE feeder lines is forecast to reach 40.0% in 2016, increasing to 46.8% by Feeder YVE-21 and YVE-22 are the heaviest loaded with utilisation forecast to reach 64.3% and 79.3% respectively by With the relatively high utilisation levels forecast on this feeder, there is insufficient back-up transfer capacity to supply the forecast demand following a network outage. YVE-21 has ties to FE-06, FE-09 and YVE-14, however these feeders are also heavily loaded and have insufficient transfer capacity to supply the forecast demand following a network outage. To ensure supply security to our customers, Jemena is proposing to undertake one feeder augmentation project at YVE within the forward planning period: Establish a tie line between YVE-21 and YVE-22 by November 2016, at an estimated cost of $710 thousand. This project involves transferring the existing YVE-22 load to BY-14 and BY-15, constructing a tie-line between YVE-21 and YVE-22, and transferring a section of the YVE-21 feeder load to YVE-22 via the new tie-line. Without implementation of this project approximately 530 kva of load reduction will be required on YVE-21 under system normal conditions, and a further 1.7 MVA of load reduction will be required under outage conditions during peak demand periods. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $47 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. 160 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

177 NETWORK DEVELOPMENT SUB-TRANSMISSION LINE LIMITATIONS This section presents information about sub-transmission line ratings and forecast loading levels for the forward planning period ( ), and the annualised cost of expected unserved energy for any identified subtransmission line limitations. Information about potential and proposed risk mitigation options are also presented for sub-transmission line limitations identified in the review process. This section also includes recently completed projects and network developments that Jemena is committed to deliver within the forward planning period. Sub-transmission line limitations Each of the identified sub-transmission line limitations and the network impacts incorporate the following annualised information for the forward planning period: The 10% probability of exceedance (POE) peak demand (MVA), being the 10% POE peak loading on the line during the peak loading period (summer or winter) with all loop lines in service. System normal loading (%), being the 10% POE peak utilisation of the line with all loop lines in service, presented as a percentage of the line s peak period rating for existing and committed sub-transmission lines. Loading with a specified line out of service (OOS) (%), being the 10% POE peak utilisation of the remaining in-service lines presented as a percentage of the lines peak period ratings. Power factor at peak load (p.u), being the power factor at the time of peak demand presented in per unit of real to apparent power demand. The value presented assumes that all capacitor banks connected within the sub-transmission loop are contributing their full reactive power capability. Maximum load at risk (MVA), being the load that would be lost if the worst credible outage occurred at the time of maximum demand. Hours at risk (h), being the number of hours where the sub-transmission line is forecast to exceed the N-1 rating in a given year and is therefore at risk of not being supplied if the worst credible outage occurs. EUSE (MWh), being the expected unserved energy associated with a network outage in a given year and the probability of that network outage actually occurring (see Section for more information). The EUSE is also weighted across two network loading scenarios, with 30% apportioned to risks associated with the 10% POE scenario and 70% apportioned to risks associated with the 50% POE scenario. The cost of USE ($ thousand), being the cost of expected unserved energy in a given year (see Section for more information). Embedded generation, being the amount of known large (units above 2 MW) embedded generation connected within the sub-transmission loop. Embedded generation has been excluded from the load at risk and expected unserved energy calculations. Load transfer capacity, which is described in detail below. For those sub-transmission lines where a risk of USE is forecast, Jemena has identified: A selection of mitigation options comprising both network, and non-network solutions. An annual maximum possible payment to non-network service providers, which is determined as the annualised capital cost for the preferred network solution, assuming a discount rate of 6.24%, and an assumed asset life of 50 years. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 161

178 5 NETWORK DEVELOPMENT Load transfer capacity Load transfer capacity is the amount of load that can potentially be transferred to adjacent sub-transmission lines or zone substations under emergency outage conditions. System normal load transfer capacities are excluded because any identified transfer capacities resulting in better network supply management would typically occur as a matter of course. Load transfer capacity will typically decrease over time due to a reliance on the available capacity of adjacent sub-transmission lines and zone substations, which decrease as network loading increases. Emergency load transfer capabilities have been excluded from the load at risk and expected unserved energy calculations, but are presented to give an indication of the additional support that can potentially be provided under emergency conditions. 162 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

179 NETWORK DEVELOPMENT BLTS-FW-BLTS SUB-TRANSMISSION LOOP Background The BLTS-FW-BLTS 66 kv sub-transmission loop supplies Footscray West Zone Substation (FW). The transmission supply point for this loop is Brooklyn Terminal Station (BLTS). Sub-transmission line ratings Table 5 90: BLTS-FW-BLTS loop ratings Summer Winter BLTS-FW1 rating 86.3 MVA 86.3 MVA BLTS-FW2 rating 65.7 MVA 86.3 MVA Network impact Table 5 91 shows the system normal and N-1 loading on each line within the sub-transmission loop connected to the transmission supply point. Table 5 91: BLTS-FW-BLTS loop loading risk and limitation cost Sub-transmission loop: BLTS-FW BLTS-FW1 Summer 10% POE peak demand (MVA) System normal loading (%) 29.1% 28.6% 27.9% 27.2% 26.7% Loading with BLTS-FW2 OOS (%) 51.2% 50.3% 49.1% 48.0% 46.9% BLTS-FW2 Summer 10% POE peak demand (MVA) System normal loading (%) 28.9% 28.5% 27.9% 27.1% 26.6% Loading with BLTS-FW1 OOS (%) 67.3% 66.1% 64.5% 63.0% 61.8% BLTS-FW Annual hours 95% of peak load expected to be reached Power factor at peak load (p.u) Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($ thousand) There are no limitations in the BLTS-FW-BLTS sub-transmission loop in the forecast period. This sub-transmission loop has no large embedded generation but up to 44.9 MVA of emergency transfer capacity in Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 163

180 5 NETWORK DEVELOPMENT Risk mitigation options considered No risk mitigation is required. Proposed preferred solution No solutions are required. 164 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

181 NETWORK DEVELOPMENT BLTS-NT-YVE-BLTS SUB-TRANSMISSION LOOP Background The BLTS-NT-YVE-BLTS 66 kv sub-transmission loop supplies Newport Zone Substation (NT) and Yarraville Zone Substation (YVE). The transmission supply point for this loop is Brooklyn Terminal Station (BLTS). Sub-transmission line ratings Table 5 92: BLTS-NT-YVE-BLTS loop ratings Summer Winter BLTS-NT rating MVA MVA BLTS-YVE rating 94.5 MVA MVA Network impact Table 5 93 shows the system normal and N-1 loading on each line within the sub-transmission loop. Table 5 93: BLTS-NT-YVE-BLTS loop loading risk and limitation cost Sub-transmission loop: BLTS-NT-YVE BLTS-NT Summer 10% POE peak demand (MVA) System normal loading (%) 41.3% 41.4% 41.4% 41.1% 40.6% Loading with BLTS-YVE OOS (%) 81.1% 81.7% 82.0% 81.6% 80.7% BLTS-YVE Summer 10% POE peak demand (MVA) System normal loading (%) 41.8% 42.2% 42.4% 42.4% 42.0% Loading with BLTS-NT OOS (%) 86.5% 87.1% 87.3% 87.0% 86.0% BLTS-NT-YVE Annual hours 95% of peak load expected to be reached Power factor at peak load (p.u) Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($ thousand) There are no limitations in the BLTS-NT-YVE-BLTS sub-transmission loop in the forecast period. This sub-transmission loop has no large embedded generation but up to 12.4 MVA of emergency transfer capacity in Risk mitigation options considered No risk mitigation is required. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 165

182 5 NETWORK DEVELOPMENT Proposed preferred solution No solutions are required. 166 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

183 NETWORK DEVELOPMENT BLTS-TH-BLTS SUB-TRANSMISSION LOOP Background The BLTS-TH-BLTS 66 kv sub-transmission loop supplies Tottenham Zone Substation (TH). The transmission supply point for this loop is Brooklyn Terminal Station (BLTS). Sub-transmission line ratings Table 5 94: BLTS-TH-BLTS loop ratings Summer Winter BLTS-TH1 rating MVA MVA BLTS-TH2 rating MVA MVA Network impact Table 5 95 shows the system normal and N-1 loading on each line within the sub-transmission loop connected to the transmission supply point. Table 5 95: BLTS-TH-BLTS loop loading risk and limitation cost Sub-transmission loop: BLTS-TH BLTS-TH1 Summer 10% POE peak demand (MVA) System normal loading (%) 14.4% 14.0% 13.6% 13.2% 13.0% Loading with BLTS-TH2 OOS (%) 28.8% 28.0% 27.3% 26.4% 26.0% BLTS-TH2 Summer 10% POE peak demand (MVA) System normal loading (%) 14.4% 14.0% 13.6% 13.2% 13.0% Loading with BLTS-TH1 OOS (%) 28.8% 28.0% 27.3% 26.4% 26.0% BLTS-TH Annual hours 95% of peak load expected to be reached Power factor at peak load (p.u) Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($ thousand) There are no limitations in the BLTS-TH-BLTS sub-transmission loop in the forecast period. This sub-transmission loop has no large embedded generation but up to 26.6 MVA of emergency transfer capacity in Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 167

184 5 NETWORK DEVELOPMENT Risk mitigation options considered No risk mitigation is required. Proposed preferred solution No solutions are required. 168 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

185 NETWORK DEVELOPMENT BTS-FF-BTS SUB-TRANSMISSION LOOP Background The BTS-FF-BTS 22 kv sub-transmission loop supplies Fairfield Zone Substation (FF). The transmission supply point for this loop is Brunswick Terminal Station (BTS). Sub-transmission line ratings Table 5 96: BTS-FF-BTS loop ratings Summer Winter BTS-FF1 rating 12.2 MVA 12.6 MVA BTS-FF2 rating 13.1 MVA 13.7 MVA BTS-FF3 rating 13.1 MVA 13.7 MVA Network impact Table 5 97 shows the system normal and N-1 loading on each line within the sub-transmission loop connected to the transmission supply point, and presents the overall sub-transmission loop limitation for the forward planning period. Table 5 97: BTS-FF-BTS loop loading risk and limitation cost Sub-transmission loop: BTS-FF BTS-FF1 Summer 10% POE peak demand (MVA) System normal loading (%) 57.4% 57.4% 58.2% 59.0% 63.1% Loading with BTS-FF2 OOS (%) 90.2% 90.2% 91.8% 93.4% 100.0% Loading with BTS-FF3 OOS (%) 90.2% 90.2% 92.6% 93.4% 100.0% BTS-FF2 Summer 10% POE peak demand (MVA) System normal loading (%) 61.8% 61.8% 63.4% 64.1% 68.7% Loading with BTS-FF1 OOS (%) 90.8% 90.1% 92.4% 93.9% 100.0% Loading with BTS-FF3 OOS (%) 98.5% 98.5% 100.8% 102.3% 109.2% BTS-FF3 Summer 10% POE peak demand (MVA) System normal loading (%) 62.6% 62.6% 64.1% 64.9% 69.5% Loading with BTS-FF1 OOS (%) 91.6% 91.6% 93.1% 94.7% 101.5% Loading with BTS-FF2 OOS (%) 99.2% 99.2% 100.8% 103.1% 109.9% BTS-FF Annual hours 95% of peak load expected to be reached Power factor at peak load (p.u) Max load at risk (MVA) Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 169

186 5 NETWORK DEVELOPMENT Hours at risk (h) EUSE (MWh) Cost of EUSE ($ thousand) There is a marginal limitation in the BTS-FF-BTS sub-transmission loop towards the end of the forward planning period. This sub-transmission loop has no large embedded generation but up to 1.5 MVA of emergency transfer capacity in 2016, which can further reduce the impact of a network outage. Risk mitigation options considered No risk mitigation is required. Proposed preferred solution No solutions are required. 170 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

187 NETWORK DEVELOPMENT BTS-NS-BTS SUB-TRANSMISSION LOOP Background The BTS-NS-BTS 22 kv sub-transmission loop supplies North Essendon Zone Substation (NS). The transmission supply point for this loop is Brunswick Terminal Station (BTS). Sub-transmission line ratings Table 5 98: BTS-NS-BTS loop ratings Summer Winter BTS-NS1 rating 15.2 MVA 15.2 MVA BTS-NS2 rating 15.2 MVA 15.2 MVA BTS-NS3 rating 15.2 MVA 21.9 MVA Network impact Table 5 99 shows the system normal and N-1 loading on each line within the sub-transmission loop connected to the transmission supply point, and presents the overall sub-transmission loop limitation for the forward planning period. Table 5 99: BTS-NS-BTS loop loading risk and limitation cost Sub-transmission loop: BTS-NS BTS-NS1 Summer 10% POE peak demand (MVA) System normal loading (%) 85.5% 85.5% 86.2% 87.5% 89.5% Loading with BTS-NS2 OOS (%) 132.9% 132.9% 134.2% 137.5% 140.1% Loading with BTS-NS3 OOS (%) 137.5% 138.2% 139.5% 142.8% 146.1% BTS-NS2 Summer 10% POE peak demand (MVA) System normal loading (%) 82.9% 82.9% 83.6% 85.5% 86.8% Loading with BTS-NS1 OOS (%) 131.6% 132.2% 133.6% 136.2% 139.5% Loading with BTS-NS3 OOS (%) 133.6% 134.2% 135.5% 138.2% 141.4% BTS-NS3 Summer 10% POE peak demand (MVA) System normal loading (%) 86.8% 86.8% 88.2% 89.5% 91.4% Loading with BTS-NS1 OOS (%) 138.8% 138.8% 140.8% 143.4% 146.7% Loading with BTS-NS2 OOS (%) 136.2% 136.2% 137.5% 140.1% 143.4% BTS-NS Annual hours 95% of peak load expected to be reached Power factor at peak load (p.u) Max load at risk (MVA) Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 171

188 5 NETWORK DEVELOPMENT Hours at risk (h) EUSE (MWh) Cost of EUSE ($ thousand) The critical limitation for the BTS-NS-BTS sub-transmission loop is thermal loading on any of the lines supplied from BTS, following an outage of any of the other loop lines, with the most onerous overload on the BTS-NS No.3 line for an outage of the BTS-NS No.1 lines. A load reduction or network support contracted embedded generation installation of approximately 14 MVA in 2016 will defer the forecast limitation to This sub-transmission loop has no large embedded generation but up to 11 MVA of emergency transfer capacity in 2016, which can further reduce the impact of a network outage. Risk mitigation options considered Five options have been considered for managing the identified network limitation: Option 1: reinforce supply to NS and surrounding areas from adjacent Essendon Zone Substation (ES). This option includes installation of a new 11 kv feeder from ES and a third transformer at ES. This will assist in reducing the load at risk on the BTS-NS lines. Option 2: install a capacitor bank at NS. This option will reduce the load at risk on the BTS-NS lines by reducing network losses and improving the power factor. Option 3: augment the BTS-NS lines. This option involves replacing sections of the BTS-NS conductors with higher rated conductor. Option 4: establish embedded generation suitably located within the sub-transmission loop. Option 5: introduce demand management to voluntarily reduce demand at peak demand times and during network outages. This involves introducing interruptible loads (as negotiated with customers) by offering incentives in the form of reduced electricity charges or outage rebates. Proposed preferred solution Jemena has identified that Option 3 maximises the net economic benefits over the life of the assets. The proposed preferred solution is planned for completion by November 2017, and has an estimated cost of $835 thousand. This project involves thermally upgrading approximately 570 metres of overhead conductor on the No.1 BTS-NS 22 kv line, replacing approximately 2.18 kilometres and thermally upgrading approximately 570 metres of overhead conductor on the No.2 BTS-NS 22 kv line, and thermally upgrading approximately 1.08 kilometres of overhead conductor on the No.3 BTS-NS 22 kv line. The works are expected to increase the summer rating of each line to approximately 20.4 MVA. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $55 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. 172 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

189 NETWORK DEVELOPMENT KTS-BY-ES-KTS SUB-TRANSMISSION LOOP Background The KTS-BY-ES-KTS 66 kv sub-transmission loop supplies Braybrook Zone Substation (BY) and Essendon Zone Substation (ES). The transmission supply point for this loop is Keilor Terminal Station (KTS). Sub-transmission line ratings Table 5 100: KTS-BY-ES-KTS loop ratings Summer Winter KTS-BY rating 72.6 MVA 83.5 MVA KTS-ES rating 83.5 MVA 91.5 MVA Network impact Table shows the system normal and N-1 loading on each line within the sub-transmission loop connected to the transmission supply point, and presents the overall sub-transmission loop limitation for the forward planning period. Table 5 101: KTS-BY-ES-KTS loop loading risk and limitation cost Sub-transmission loop: KTS-BY-ES KTS-BY Summer 10% POE peak demand (MVA) System normal loading (%) 46.8% 47.1% 47.0% 46.8% 46.8% Loading with KTS-ES OOS (%) 126.4% 127.1% 127.0% 126.3% 125.9% KTS-ES Summer 10% POE peak demand (MVA) System normal loading (%) 64.6% 64.9% 64.8% 64.4% 64.3% Loading with KTS-BY OOS (%) 107.2% 107.9% 107.7% 107.2% 106.9% KTS-BY-ES Annual hours 95% of peak load expected to be reached Power factor at peak load (p.u) Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($ thousand) The critical limitation for the KTS-BY-ES-KTS sub-transmission loop is thermal loading of the KTS-BY line, following an outage of the KTS-ES line. A load reduction or network support contracted embedded generation installation of approximately 20 MVA in 2016 will defer the forecast limitation beyond the forward planning period (noting there is no forecast demand growth for this sub-transmission loop). Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 173

190 5 NETWORK DEVELOPMENT The sub-transmission loop has no large embedded generation but up to 53.5 MVA of emergency transfer capacity in 2016, which can further reduce the impact of a network outage. Risk mitigation options considered Three options have been considered for managing the identified network limitation: Option 1: augment the KTS-BY line, which involves replacing lower rated conductor sections of this line with 37/3.75 mm AAC conductor. Option 2: establish embedded generation suitably located within the sub-transmission loop. Option 3: introduce demand management to voluntarily reduce demand at peak demand times and during network outages. This would involve the introduction of interruptible loads, as negotiated with customers, by offering incentives in the form of reduced electricity charges or outage rebates. Proposed preferred solution Despite existing load at risk, due to the relatively low probability of a line outage during the peak demand period, there is only a small amount of expected unserved energy each year. With the forecast demand growth being relatively flat over the forward planning period, there is insufficient risk to economically justify any of the risk mitigation options identified. Additionally, to help manage the substation capacity limitations, Jemena is proposing to install two 8 MVAR capacitor banks at BY in November 2018, at an estimated cost of $2.2 million. This proposed augmentation will also reduce electrical losses and loading on the sub-transmission lines, delaying the need for further augmentation. Jemena will continue managing the existing risk without further network augmentation, and will continue to monitor and report any supply risks in future DAPRs. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $144 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. 174 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

191 NETWORK DEVELOPMENT KTS-MAT-AW-PV-KTS SUB-TRANSMISSION LOOP Background The KTS-MAT-AW-PV-KTS 66 kv sub-transmission loop supplies the Melbourne Airport Zone Substation (MAT), Airport West Zone Substation (AW), Pascoe Vale Zone Substation (PV), and Tullamarine Zone Substation (TMA). TMA was commissioned this year. The transmission supply point for this loop is Keilor Terminal Station (KTS). Primarily due to expansion plans at Melbourne Airport (Tullamarine), Jemena is forecasting rapid load increases on the KTS-MAT-AW-PV-KTS 66 kv sub-transmission loop within the forward planning period. Sub-transmission line ratings Table 5 102: KTS-MAT-AW-PV-KTS loop ratings Summer Winter KTS-TMA rating MVA MVA KTS-AW rating MVA MVA KTS-PV rating MVA MVA Network impact Table 5 103, shows the system normal and N-1 loading on each line within the sub-transmission loop connected to the transmission supply point, and presents the overall sub-transmission loop limitation for the forward planning period. Table 5 103: KTS-MAT-AW-PV-KTS loop loading risk and limitation cost Sub-transmission loop: KTS-MAT-AW-PV KTS-TMA Summer 10% POE peak demand (MVA) System normal loading (%) 61.7% 68.1% 69.3% 71.0% 72.4% Loading with KTS-AW OOS (%) 112.3% 120.9% 123.4% 126.3% 129.2% Loading with KTS-PV OOS (%) 72.0% 78.7% 80.1% 81.9% 83.4% KTS-AW Summer 10% POE peak demand (MVA) System normal loading (%) 76.2% 79.3% 80.7% 82.6% 84.4% Loading with KTS-TMA OOS (%) 120.8% 128.5% 131.2% 134.4% 137.4% Loading with KTS-PV OOS (%) 99.6% 103.3% 105.0% 107.4% 109.7% KTS-PV Summer 10% POE peak demand (MVA) System normal loading (%) 36.9% 38.0% 38.4% 39.1% 39.7% Loading with KTS-TMA OOS (%) 52.2% 54.8% 55.7% 56.8% 57.8% Loading with KTS-AW OOS (%) 76.4% 79.0% 80.5% 82.1% 83.9% Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 175

192 5 NETWORK DEVELOPMENT KTS-MAT-AW-PV Annual hours 95% of peak load expected to be reached Power factor at peak load (p.u) Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($ thousand) , , ,560.8 There are two critical thermal loading limitations for the KTS-MAT-AW-PV-KTS sub-transmission loop: The KTS-AW line, following an outage of the KTS-TMA line, or KTS-PV line. The KTS-TMA line, following an outage of the KTS-AW line. Jemena completed an upgrade of the KTS-AW 66 kv line in November The project involved replacing 1.3 kilometres of overhead conductor with higher capacity conductor. This upgrade increased the summer rating on the KTS-AW 66 kv line from 101 MVA to approximately 117 MVA, which is the upper limit of capability for similar 66 kv lines. Augmentation of the KTS-PV, and KTS-TMA 66 kv lines will not substantially change the overall capacity of this sub-transmission loop. A load reduction or network support contracted embedded generation installation of approximately 13.5 MVA in 2017 will defer the forecast limitation to This sub-transmission loop has 8.0 MW of large embedded generation, and up to 8.0 MVA of emergency transfer capacity in 2016, both of which can further reduce the impact of a network outage. Risk mitigation options considered Four options have been considered for managing the identified network limitation: Option 1: split the KTS-MAT-AW-PV-KTS loop. Option 2: establish embedded generation suitably located within the sub-transmission loop. Option 3: introduce demand management to voluntarily reduce demand at peak demand times and during network outages. This involves introducing interruptible loads (as negotiated with customers) by offering incentives in the form of reduced electricity charges or outage rebates. Proposed preferred solution Customer driven load increase is the primary driver of the need to increase the KTS-MAT-AW-PV-KTS 66 kv loop capacity, and the preferred option is to split the loop at an estimated cost of $11.1 million. The proposed preferred solution will be required by November 2017 or November 2018 depending on customer supply requirements. This project involves the formation of one loop supplying TMA and MAT, and the other loop supplying AW and PV. Separation of the loop into a KTS-MAT-TMA-KTS loop and a KTS-AW-PV-KTS loop will include: Converting the existing KTS-TMA 66 kv single circuit into a double circuit line. Converting the existing KTS-AW 66 kv single circuit into a double circuit line. 176 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

193 NETWORK DEVELOPMENT 5 Establishing one additional freeway crossing and rearranging the circuits to form the two separate loops. Establishing two additional 66 kv line exits at KTS. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $731 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 177

194 5 NETWORK DEVELOPMENT KTS-MLN-SBY-SHM-KTS SUB-TRANSMISSION LOOP Background The KTS-MLN-SBY (WND-GSB)-SHM-KTS 66 kv sub-transmission loop supplies Jemena s Sunbury Zone Substation (SBY) and Sydenham Zone Substation (SHM), and Powercor s Gisborne (GSB), Melton (MLN), and Woodend (WND) zone substations. Its transmission supply point is Keilor Terminal Station (KTS). Sub-transmission line ratings Table 5 104: KTS-MLN-SBY (WND-GSB)-SHM-KTS loop ratings Summer Winter KTS-MLN rating 94.0 MVA MVA KTS-SBY rating 96.0 MVA MVA KTS-SMH rating MVA MVA Network impact Table 5 105, shows the system normal and N-1 loading on each line within the sub-transmission loop connected to the transmission supply point, and presents the overall sub-transmission loop limitation for the forward planning period. Table 5 105: KTS-MLN-SBY (WND-GSB)-SHM-KTS loop loading risk and limitation cost Sub-transmission loop: KTS-MLN-SBY (WND-GSB)-SHM KTS-MLN Summer 10% POE peak demand (MVA) System normal loading (%) 76.9% 79.9% 83.5% 87.3% 91.3% Loading with KTS-SBY OOS (%) 125.1% 126.5% 132.7% 137.6% 141.3% Loading with KTS-SMH OOS (%) 114.0% 120.2% 125.9% 135.7% 141.7% KTS-SHM Summer 10% POE peak demand (MVA) System normal loading (%) 80.7% 83.2% 86.8% 90.7% 95.0% Loading with KTS-MLN OOS (%) 119.5% 121.3% 125.7% 130.6% 137.0% Loading with KTS-SBY OOS (%) 134.4% 140.9% 147.5% 159.7% 166.4% KTS-SBY Summer 10% POE peak demand (MVA) System normal loading (%) 85.5% 88.6% 92.9% 97.4% 102.3% Loading with KTS-MLN OOS (%) 139.1% 140.8% 146.3% 151.8% 159.5% Loading with KTS-SHM OOS (%) 180.2% 179.8% 188.2% 194.9% 198.9% KTS-MLN-SBY (WND-GSB)-SHM Annual hours 95% of peak load expected to be reached Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

195 NETWORK DEVELOPMENT 5 Power factor at peak load (p.u) Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($k) , , ,794.3 The critical limitation for the KTS-MLN-SBY (WND-GSB)-SHM-KTS sub-transmission loop is a combination of: Thermal loading on any of the remaining in-service lines supplied from KTS, following an outage of any line supplied from KTS, with the overload most onerous on the KTS-SBY line for an outage of the KTS- SHM line. Voltage collapse of the entire loop following an outage of any line supplied from KTS, which becomes more critical during the later years of the forward planning period. While voltage collapse can be mitigated with additional reactive support (shunt capacitor banks), as the loop demand increases the magnitude of reactive support required makes this an impractical long-term solution. A load reduction or network support contracted embedded generation installation of approximately 172 MVA in 2016 would defer the forecast limitation to This sub-transmission loop has no large embedded generation but up to 4.2 MVA of emergency transfer capacity in 2016, which can be utilised to reduce the network limitation. Risk mitigation options considered Five options have been considered for managing the identified network limitation: Option 1: augment the KTS-SBY line. This option involves replacing sections of steel, aluminium, aluminium with steel reinforcement, and copper conductor sections of the line with the 37/3.75 mm AAC conductor. Option 2: install capacitor banks at SBY and/or SHM to reduce losses, improve the power factor and thereby offload the loop lines. Option 3: establish a new No.2 KTS-SBY 66 kv line by purchasing sections of the existing KTS-MLN-SBY 66 kv line from Powercor and carrying out associated line rerouting works (following establishment of Deer Park Terminal Station (DPTS)). Option 4: establish embedded generation suitably located within the sub-transmission loop. Option 5: introduce demand management to voluntarily reduce demand at peak demand times and during network outages. This involves introducing interruptible loads (as negotiated with customers) by offering incentives in the form of reduced electricity charges or outage rebates. Proposed preferred solution In June 2014 the Australian Energy Market Operator (AEMO) issued an invitation to tend (ITT) for the procurement of DPTS. The ITT was for detailed design, site preparation, procurement of plant and equipment, construction, co-ordination of interface works, commissioning, practical completion and delivery of the shared transmission services for a thirty year period. The ITT followed conclusion of a regulatory investment test jointly conducted by AEMO, Jemena and Powercor for addressing the capacity constraints at KTS. Establishment of DPTS will allow for the transfer of MLN to Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 179

196 5 NETWORK DEVELOPMENT DPTS, which will remove the identified loading limitation on the KTS-SBY (WND-GSB)-SHM-KTS loop. The ITT nominated a practical completion date of 1 November As part of the establishment of DPTS, Jemena is planning to purchase sections of the existing KTS-MLN-SBY 66 kv line from Powercor and install new conductors to form a new No.2 KTS-SBY 66 kv line to continue supplying SBY, WND, GSB and SHM. Purchase of the line, and associated line rerouting works, are proposed for November 2017, at an estimated cost of $6.3 million. 180 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

197 NETWORK DEVELOPMENT SMTS-SSS-ST-SMTS SUB-TRANSMISSION LOOP Background The SMTS-SSS-ST-SMTS 66 kv sub-transmission loop supplies Somerton Zone Substation (ST) and the Somerton Switching Station (SSS), to which the AGL owned Somerton Power Station (SPS) is connected. Somerton Power Station is a gas powered peaking generator with a nameplate capacity of 150 MW. The transmission supply point for this loop is South Morang Terminal Station (SMTS). Sub-transmission line ratings Table 5 106: SMTS-SSS-ST-SMTS loop ratings Summer Winter SMTS-SSS rating MVA MVA SMTS-ST rating MVA MVA Network impact Table 5 107, shows the system normal and N-1 loading on each line within the sub-transmission loop connected to the transmission supply point. Table 5 107: SMTS-SSS-ST-SMTS loop loading risk and limitation cost Sub-transmission loop: SMTS-SSS-ST SMTS-SSS Summer 10% POE peak demand (MVA) System normal loading (%) 26.7% 28.1% 29.6% 31.1% 33.1% Loading with SMTS-ST OOS (%) 72.8% 76.5% 80.8% 85.8% 92.9% SMTS-ST Summer 10% POE peak demand (MVA) System normal loading (%) 42.3% 44.5% 46.9% 49.3% 52.5% Loading with SMTS-SSS OOS (%) 70.5% 73.8% 78.1% 82.3% 87.8% SMTS-SSS-ST Annual hours 95% of peak load expected to be reached Power factor at peak load (p.u) Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($k) There are no limitations in the SMTS-SSS-ST-SMTS sub-transmission loop in the forecast period. This sub-transmission loop has 150 MW of large embedded generation, and up to 30.8 MVA of emergency transfer capacity in Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 181

198 5 NETWORK DEVELOPMENT Risk mitigation options considered No risk mitigation is required. Proposed preferred solution No solutions are required. 182 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

199 NETWORK DEVELOPMENT TSTS-HB-L-Q-TSTS SUB-TRANSMISSION LOOP Background The TSTS-HB-L-Q-TSTS 66 kv sub-transmission loop supplies Jemena s Heidelberg Zone Substation (HB), and Citipower s Deepdene (L) and Kew (Q) zone substations. Its transmission supply point is Templestowe Terminal Station (TSTS). Sub-transmission line ratings Table 5 108: TSTS-HB-L-Q-TSTS loop ratings Summer Winter TSTS-HB rating MVA MVA TSTS-L rating MVA MVA Network impact Table 5 109, shows the system normal and N-1 loading on each line within the sub-transmission loop connected to the transmission supply point. Table 5 109: TSTS-HB-L-Q-TSTS loop loading risk and limitation cost Sub-transmission loop: TSTS-HB-L-Q TSTS-HB Summer 10% POE peak demand (MVA) System normal loading (%) 59.1% 59.3% 60.0% 61.1% 63.8% Loading with TSTS-L OOS (%) 112.6% 113.8% 114.6% 119.4% 119.8% TSTS-Q Summer 10% POE peak demand (MVA) System normal loading (%) 54.9% 54.9% 55.6% 58.4% 56.9% Loading with TSTS-HB OOS (%) 128.6% 129.5% 130.4% 135.1% 136.5% TSTS-HB-Q Annual hours 95% of peak load expected to be reached Power factor at peak load (p.u) Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($k) The critical limitations for the TSTS-HB-L-Q-TSTS sub-transmission loop are thermal loading of: The TSTS-L line, following an outage of the TSTS-HB line. The TSTS-HB line, following an outage of the TSTS-L line. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 183

200 5 NETWORK DEVELOPMENT A load reduction or network support contracted embedded generation installation of approximately 31 MVA in 2016 would defer the forecast limitation to This sub-transmission loop does not have any large embedded generation or emergency transfer capacity. Risk mitigation options considered Three options have been considered for managing the identified network limitation: Option 1: installation of a new 8 MVAR capacitor bank to provide the required reactive support to mitigate the power factor limitation. Option 2: establish embedded generation suitably located in the HB supply area, with sufficient reactive support to mitigate the power factor limitation. Option 3: introduce demand management to voluntarily reduce demand at peak demand times and during network outages. This involves introducing interruptible loads (as negotiated with customers) by offering incentives in the form of reduced electricity charges or outage rebates. Proposed preferred solution Jemena is proposing to install a new 8 MVAR capacitor bank at HB by November 2020, at an estimated cost of $1.4 million. This proposed augmentation will reduce electrical losses, and thereby loading, on the subtransmission lines and delay the need for more costly augmentation. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $93 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. 184 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

201 NETWORK DEVELOPMENT TTS-BD-BMS-VCO-COO-TTS SUB-TRANSMISSION LOOP Background The TTS-BD-BMS-COO-TTS 66 kv sub-transmission loop supplies Broadmeadows Zone Substation (BD), Broadmeadows South Zone Substation (BMS), Coolaroo Zone Substation (COO) and the customer owned Visy-Paper Zone Substation (VCO). The transmission supply point for this loop is Thomastown Terminal Station (TTS). With completion of BMS in June 2015, the TTS-BMS line increased its summer rating from 89.7 MVA and its winter rating from 93.2 MVA to MVA and MVA respectively. Sub-transmission line ratings Table 5 110: TTS-BD-BMS-VCO-COO-TTS loop ratings Summer Winter TTS-BMS rating MVA MVA TTS-BD rating MVA MVA TTS-COO rating MVA MVA Network impact Table 5 111, shows the system normal and N-1 loading on each line within the sub-transmission loop connected to the transmission supply point, and presents the overall sub-transmission loop limitation for the forward planning period. Table 5 111: TTS-BD-BMS-VCO-COO-TTS loop loading risk and limitation cost Sub-transmission loop: TTS-BD-BMS-VCO-COO TTS-BMS (TTS-BD1) Summer 10% POE peak demand (MVA) System normal loading (%) 62.6% 61.9% 62.5% 62.7% 62.9% Loading with TTS-BD OOS (%) 103.7% 102.6% 103.2% 103.4% 103.5% Loading with TTS-COO OOS (%) 97.8% 96.8% 97.8% 98.1% 98.5% TTS-BD (TTS-BD2) Summer 10% POE peak demand (MVA) System normal loading (%) 63.1% 62.1% 62.6% 62.8% 63.0% Loading with TTS-BMS OOS (%) 97.1% 95.8% 96.5% 96.7% 96.8% Loading with TTS-COO OOS (%) 101.6% 100.3% 101.4% 101.6% 102.0% TTS-COO Summer 10% POE peak demand (MVA) System normal loading (%) 73.5% 73.0% 73.5% 73.9% 74.6% Loading with TTS-BMS OOS (%) 101.7% 100.7% 101.6% 102.0% 102.6% Loading with TTS-BD OOS (%) 110.8% 109.7% 110.5% 110.9% 111.5% Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 185

202 5 NETWORK DEVELOPMENT TTS-BD-BMS-VCO-COO Annual hours 95% of peak load expected to be reached Power factor at peak load (p.u) Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($k) The critical limitation for the TTS-BD-BMS-VCO-COO-TTS sub-transmission loop is thermal loading of: The TTS-COO line, following outage of the TTS-BD line. A load reduction or network support contracted embedded generation installation of approximately 23 MVA in 2016 would defer the forecast limitation until This sub-transmission loop has 10.5 MW of large embedded generation and up to 26.5 MVA of emergency transfer capacity in 2016, both of which can further reduce the impact of a network outage. Risk mitigation options considered Three options have been considered for managing the identified network limitation: Option 1: augment the TTS-BMS and TTS-COO lines, which involve replacing the smaller sized conductor sections of this line with 37/3.75 mm AAC conductor. Option 2: establish embedded generation suitably located within the sub-transmission loop. Option 3: introduce demand management to voluntarily reduce demand at peak demand times and during network outages. This involves introducing interruptible loads (as negotiated with customers) by offering incentives in the form of reduced electricity charges or outage rebates. Proposed preferred solution Despite existing load at risk, due to the low probability of a line outage concurrent with the peak demand period, there is only a small amount of expected unserved energy each year. With the forecast demand growth being relatively flat over the forward planning period for this loop, primarily due to the planned closure of Ford Australia s Broadmeadows operations, there is insufficient risk to economically justify any of the risk mitigation options identified. Jemena will manage the existing risk without further network augmentation at this time, and will continue to monitor and report any BD, BMS and COO supply risks in future DAPR s. 186 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

203 NETWORK DEVELOPMENT TTS-CN-CS-TTS SUB-TRANSMISSION LOOP Background The TTS-CN-CS-TTS 66 kv sub-transmission loop supplies Coburg North Zone Substation (CN) and Coburg South Zone Substation (CS). The transmission supply point for this loop is Thomastown Terminal Station (TTS). Sub-transmission line ratings Table 5 112: TTS-CN-CS-TTS loop ratings Summer Winter TTS-CN rating MVA MVA TTS-CS rating MVA MVA Network impact Table 5 113, shows the system normal and N-1 loading on each line within the sub-transmission loop connected to the transmission supply point, and presents the overall sub-transmission loop limitation for the forward planning period. Table 5 113: TTS-CN-CS-TTS loop loading risk and limitation cost Sub-transmission loop: TTS-CN-CS TTS-CN Summer 10% POE peak demand (MVA) System normal loading (%) 64.8% 66.6% 67.6% 68.3% 68.9% Loading with TTS-CS OOS (%) 105.3% 108.2% 110.6% 111.9% 113.1% TTS-CS Summer 10% POE peak demand (MVA) System normal loading (%) 39.1% 40.1% 41.0% 41.8% 42.3% Loading with TTS-CN OOS (%) 108.6% 112.0% 114.1% 115.9% 117.2% TTS-CN-CS Annual hours 95% of peak load expected to be reached Power factor at peak load (p.u) Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($k) The critical limitation for the TTS-CN-CS-TTS sub-transmission loop is thermal loading of: The TTS-CN line, following an outage of the TTS-CS line. The TTS-CS line, following an outage of the TTS-CN line. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 187

204 5 NETWORK DEVELOPMENT A load reduction or network support contracted embedded generation installation of approximately 10 MVA in 2016 would defer the forecast limitation by 12 months. This sub-transmission loop has 2.0 MW of large embedded generation and up to 15.0 MVA of emergency transfer capacity in 2016, both of which can further reduce the impact of a network outage. Risk mitigation options considered Four options have been considered for managing the identified network limitation: Option 1: install a new 8 MVAR capacitor bank at CS. Option 2: establish a third 66 kv line to either CN or CS. This option will alleviate the emerging constraints. Option 3: establish embedded generation suitably located in the COO supply area. Option 4: introduce demand management to voluntarily reduce demand at peak demand times and during network outages. This involves introducing interruptible loads (as negotiated with customers) by offering incentives in the form of reduced electricity charges or outage rebates. Proposed preferred solution Jemena has identified that Option 1, installation of an 8 MVAR capacitor bank, will maximise the net economic benefit. The new capacitor bank will help provide additional capacity at CS and offload the TTS-CN-CS-TTS 66 kv sub-transmission line loop by improving the power factor and reducing electrical losses on the subtransmission lines and power transformers. This option will defer the requirement for implementation of more costly augmentation options. Jemena is proposing to install the new capacitor bank by November 2017, and the project has an estimated cost of $1.0 million. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $67 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. 188 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

205 NETWORK DEVELOPMENT TTS-EP-EPN-P-TTS SUB-TRANSMISSION LOOP Background The TTS-EP-P-TTS 66 kv sub-transmission loop supplies Preston Zone Substation (P) and East Preston Zone Substation (EP). The transmission supply point for this loop is Thomastown Terminal Station (TTS). Sub-transmission line ratings Table 5 114: TTS-EP-P-TTS loop ratings Summer Winter TTS-EP rating 78.9 MVA 93.2 MVA TTS-P rating 81.2 MVA MVA Network impact Table 5 115, shows the system normal and N-1 loading on each line within the sub-transmission loop connected to the transmission supply point, and presents the overall sub-transmission loop limitation for the forward planning period. Table 5 115: TTS-EP-P-TTS loop loading risk and limitation cost Sub-transmission loop: TTS-EP-EPN-P TTS-EP Summer 10% POE peak demand (MVA) System normal loading (%) 25.0% 25.2% 25.5% 25.2% 25.1% Loading with TTS-EP OOS (%) 62.6% 63.1% 63.5% 63.0% 62.6% TTS-P Summer 10% POE peak demand (MVA) System normal loading (%) 36.1% 36.3% 36.6% 36.5% 36.2% Loading with TTS-P OOS (%) 60.7% 61.2% 61.6% 61.1% 60.7% TTS-EP-EPN-P Annual hours 95% of peak load expected to be reached Power factor at peak load (p.u) Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($k) There are no limitations in the TTS-EP-EPN-P-TTS sub-transmission loop in the forecast period. This sub-transmission loop has no large embedded generation but up to 1.6 MVA of emergency transfer capacity in Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 189

206 5 NETWORK DEVELOPMENT Risk mitigation options considered No risk mitigation is required. Proposed preferred solution No solutions are required. 190 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

207 NETWORK DEVELOPMENT TTS-NEI-NH-WT-TTS SUB-TRANSMISSION LOOP Background The TTS-NEI-NH-WT-TTS 66 kv sub-transmission loop supplies Jemena s North Heidelberg Zone Substation (NH), AusNet Services Watsonia Zone Substation (WT), and the Nilsen Electrical Industries customer substation (NEI). The transmission supply point for this loop is Thomastown Terminal Station (TTS). Sub-transmission line ratings Table 5 116: TTS-NEI-NH-WT-TTS loop ratings Summer Winter TTS-NH rating MVA MVA TTS-WT rating MVA MVA Network impact Table 5 117, shows the system normal and N-1 loading on each line within the sub-transmission loop connected to the transmission supply point, and presents the overall sub-transmission loop limitation for the forward planning period. Table 5 117: TTS-NEI-NH-WT-TTS loop loading risk and limitation cost Sub-transmission loop: TTS-NEI-NH-WT TTS-NH Summer 10% POE peak demand (MVA) System normal loading (%) 72.5% 74.7% 75.7% 76.4% 77.0% Loading with TTS-WT OOS (%) 122.0% 125.6% 127.6% 128.2% 129.9% TTS-WT Summer 10% POE peak demand (MVA) System normal loading (%) 47.1% 48.1% 48.9% 49.5% 49.9% Loading with TTS-NEI OOS (%) 123.7% 127.6% 129.4% 130.4% 131.7% TTS-NEI-NH-WT Annual hours 95% of peak load expected to be reached Power factor at peak load (p.u) Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($k) The critical limitation for the TTS-NEI-NH-WT-TTS sub-transmission loop is thermal loading of: The TTS-NH line, following an outage of the TTS-WT line. The TTS-WT line, following an outage of the TTS-NH line. Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 191

208 5 NETWORK DEVELOPMENT A load reduction or network support contracted embedded generation installation of approximately 28 MVA in 2016 would defer the forecast limitation for 12 months. This sub-transmission loop has no large embedded generation but up to 4.5 MVA of emergency transfer capacity in 2016, which can further reduce the impact of a network outage. Risk mitigation options considered Three options have been considered for managing the identified limitations: Option 1: installation of a new 8 MVAR capacitor bank to provide the required reactive support to mitigate the power factor limitation. Option 2: establish a third 66 kv line to NH or WT to alleviate the existing line loading limitation. Option 3: establish embedded generation suitably located in the NH supply area, with sufficient reactive support to mitigate the power factor limitation. Option 4: introduce demand management to voluntarily reduce demand at peak demand times and during network outages. This involves introducing interruptible loads (as negotiated with customers) by offering incentives in the form of reduced electricity charges or outage rebates. Proposed preferred solution Jemena is proposing to install a new 8 MVAR capacitor bank at NH by November 2018, at an estimated cost of $1.3 million. This proposed augmentation will improve the power factor, reduce electrical losses and thereby loading on the sub-transmission lines, and delay the need for a more costly augmentation. An annual maximum possible payment to non-network service providers to address the risk of EUSE is approximately $86 thousand. A non-network solution providing a lower level of capacity than offered by the preferred network solution would receive a proportionally lower annual payment. 192 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

209 NETWORK DEVELOPMENT WMTS-FE-WMTS SUB-TRANSMISSION LOOP Background The WMTS-FE-WMTS 66 kv sub-transmission loop supplies Footscray East Zone Substation (FE). The transmission supply point for this loop is West Melbourne Terminal Station (WMTS). Sub-transmission line ratings Table 5 118: WMTS-FE-WMTS loop ratings Summer Winter WMTS-FE1 rating 83.5 MVA 91.5 MVA WMTS-FE2 rating 83.0 MVA 91.5 MVA Network impact Table 5 119, shows the system normal and N-1 loading on each line within the sub-transmission loop connected to the transmission supply point, and presents the overall sub-transmission loop limitation for the forward planning period. Table 5 119: WMTS-FE-WMTS loop loading risk and limitation cost Sub-transmission loop: WMTS-FE WMTS-FE1 Summer 10% POE peak demand (MVA) System normal loading (%) 23.2% 23.4% 23.9% 24.6% 25.7% Loading with WMTS-FE2 OOS (%) 40.7% 41.3% 42.0% 43.4% 45.3% WMTS-FE2 Summer 10% POE peak demand (MVA) System normal loading (%) 17.7% 18.0% 18.3% 18.9% 19.8% Loading with WMTS-FE1 OOS (%) 41.2% 41.8% 42.5% 44.0% 45.9% WMTS-FE Annual hours 95% of peak load expected to be reached Power factor at peak load (p.u) Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($k) There are no limitations in the WMTS-FE-WMTS sub-transmission loop in the forecast period. This sub-transmission loop has no large embedded generation but up to 27.6 MVA of emergency transfer capacity in Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 193

210 5 NETWORK DEVELOPMENT Risk mitigation options considered No risk mitigation is required. Proposed preferred solution No solutions are required. 194 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

211 NETWORK DEVELOPMENT WMTS-FT-WMTS SUB-TRANSMISSION LOOP Background The WMTS-FT-WMTS 66 kv sub-transmission loop supplies Flemington Zone Substation (FT). The transmission supply point for this loop is West Melbourne Terminal Station (WMTS). Sub-transmission line ratings Table 5 120: WMTS-FT-WMTS loop ratings Summer Winter WMTS-FT1 rating 52.0 MVA 64.0 MVA WMTS-FT2 rating 65.2 MVA 76.6 MVA Network impact Table 5 121, shows the system normal and N-1 loading on each line within the sub-transmission loop, and presents the overall sub-transmission loop limitation for the forward planning period. Table 5 121: WMTS-FT-WMTS loop loading risk and limitation cost Sub-transmission loop: WMTS-FT WMTS-FT1 Summer 10% POE peak demand (MVA) System normal loading (%) 35.4% 36.2% 36.9% 37.7% 38.7% Loading with WMTS-FT2 OOS (%) 72.3% 73.7% 75.6% 77.5% 79.8% WMTS-FT2 Summer 10% POE peak demand (MVA) System normal loading (%) 28.4% 28.8% 29.4% 30.1% 31.0% Loading with WMTS-FT1 OOS (%) 57.8% 58.7% 60.4% 61.8% 63.8% WMTS-FT Annual hours 95% of peak load expected to be reached Power factor at peak load (p.u) Max load at risk (MVA) Hours at risk (h) EUSE (MWh) Cost of EUSE ($k) There are no limitations in the WMTS-FT-WMTS sub-transmission loop in the forecast period. This sub-transmission loop has no large embedded generation but up to 2.7 MVA of emergency transfer capacity in Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd 195

212 5 NETWORK DEVELOPMENT Risk mitigation options considered No risk mitigation is required. Proposed preferred solution No solutions are required. 196 Public 24 December 2015 Jemena Electricity Networks (Vic) Ltd

213 Appendix A Feeder Line Loadings