Distribution and Transmission Annual Planning Report December 2020

Disclaimer Ausgrid is registered as both a Distribution Network Service Provider and a Transmission Network Service Provider. This Distribution and Transmission Annual Planning Report 2020 has been prepared and published by Ausgrid under clause 5.13.2 and 5.12.2 of the National Electricity Rules to notify Registered Participants and Interested Parties of the results of the distribution and transmission network annual planning review and should only be used for those purposes. This document does not purport to contain all of the information that a prospective investor or participant or potential participant in the National Electricity Market, or any other person or interested parties may require. In preparing this document it is not possible nor is it intended for Ausgrid to have regard to the investment objectives, financial situation and particular needs of each person who reads or uses this document. In all cases, anyone proposing to rely on or use the information in this document should independently verify and check the accuracy, completeness, reliability and suitability of that information for their own purposes. Accordingly, Ausgrid makes no representations or warranty as to the accuracy, reliability, completeness or suitability for particular purposes of the information in this document. Persons reading or utilising this document acknowledge that Ausgrid and their employees, agents and consultants shall have no liability (including liability to any person by reason of negligence or negligent misstatement) for any statements, opinions, information or matter (expressed or implied) arising out of, contained in or derived from, or for any omissions from, the information in this document, except insofar as liability under any New South Wales and Commonwealth statute cannot be excluded.

DOCUMENT AND AMENDMENT HISTORY

Issue Date Approved by Summary of Changes No.

1 December 2020 Executive Initial Issue General Manager – Asset Management

Contact For all enquiries regarding the Distribution and Transmission Annual Planning Report 2020 and for making written submissions contact: Ausgrid Head of Asset Investment GPO Box 4009 Sydney NSW 2001 Email: [email protected]

Contents 1 EXECUTIVE SUMMARY ...... 1 2 INTRODUCTION ...... 2 2.1 About Ausgrid ...... 2 2.1.1 Our purpose and vision ...... 2 2.1.2 Our operating environment ...... 3 2.2 Ausgrid’s network ...... 4 2.2.1 Number and types of network assets ...... 4 2.3 Annual planning review ...... 6 2.3.1 Distribution ...... 6 2.3.2 Transmission ...... 6 2.3.3 Distribution and Transmission Annual Planning Review and Reporting ...... 6 2.4 Ausgrid’s planning approach ...... 6 2.4.1 Investment objectives and decision criteria ...... 7 2.4.2 Network planning process ...... 8 2.4.3 Network area plans ...... 9 2.5 Significant changes from previous DTAPR ...... 9 2.6 Distribution System Limitations Template – Online Data ...... 9 3 FORECASTS FOR THE FORWARD PLANNING PERIOD ...... 11 3.1 Data tables online ...... 11 3.2 Zone and Subtransmission substation load forecasting methodology ...... 12 3.2.1 Spatial trend component of forecast ...... 12 3.2.2 System level econometric model component of forecast ...... 13 3.2.3 Assumptions applied to substation load forecasts ...... 14 3.2.4 Explanation of substation forecast outcomes ...... 16 3.3 Transmission - distribution connection point load forecasts ...... 17 3.4 Subtransmission feeder load forecasts ...... 17 3.5 Primary distribution feeder load forecasts ...... 18 3.5.1 Load transfer capacities of zone substations ...... 18 3.6 Other factors having a material impact on the network ...... 18 3.6.1 Fault levels ...... 18 3.6.2 Voltage levels ...... 19 3.6.3 Other power system security requirements ...... 19 3.6.4 Quality of supply ...... 19 3.6.5 Embedded generation ...... 19 3.7 Additional notes ...... 20 3.7.1 Integrated System Plan ...... 20 4 NETWORK ASSET RETIREMENTS AND DERATINGS ...... 21 4.1 Feeder S20 and S21 De-rating ...... 21 5 DISTRIBUTION LOAD AREAS ...... 22 5.1 Camperdown and Blackwattle Bay load area...... 23 5.1.1 Description of Camperdown and Blackwattle Bay load area ...... 23 5.1.2 Identified system limitations...... 24 5.1.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects 24 5.2 Canterbury Bankstown load area ...... 25 5.2.1 Description of Canterbury Bankstown load area ...... 25 5.2.2 Identified system limitations...... 26 5.2.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects 26 5.3 Carlingford load area ...... 27 5.3.1 Description of Carlingford load area ...... 27 5.3.2 Identified system limitations...... 28 5.3.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects 28 5.4 Eastern Suburbs load area ...... 29 5.4.1 Description of Eastern Suburbs load area ...... 29 5.4.2 Identified system limitations...... 30 5.4.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects 30 5.5 Greater Cessnock load area ...... 31 5.5.1 Description of Greater Cessnock load area ...... 31

5.5.2 Identified system limitations...... 32 5.5.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects 32 5.6 Inner West load area ...... 33 5.6.1 Description of Inner West load area ...... 33 5.6.2 Identified system limitations...... 34 5.6.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects 34 5.7 Lower Central Coast load area ...... 35 5.7.1 Description of Lower Central Coast load area ...... 35 5.7.2 Identified system limitations...... 36 5.7.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects 36 5.8 Lower North Shore load area ...... 37 5.8.1 Description of Lower North Shore load area ...... 37 5.8.2 Identified system limitations...... 38 5.8.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects 38 5.9 Maitland load area ...... 39 5.9.1 Description of Maitland load area ...... 39 5.9.2 Identified system limitations...... 40 5.9.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects 40 5.10 Manly Warringah load area ...... 41 5.10.1 Manly Warringah load area ...... 41 5.10.2 Identified system limitations...... 42 5.10.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects 42 5.11 Newcastle Inner City load area ...... 43 5.11.1 Newcastle Inner City load area ...... 43 5.11.2 Identified system limitations...... 44 5.11.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects 44 5.12 Newcastle Ports load area ...... 45 5.12.1 Description of Newcastle Ports load area ...... 45 5.12.2 Identified system limitations...... 46 5.12.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects 46 5.13 Newcastle Western Corridor load area ...... 47 5.13.1 Description of Newcastle Western Corridor load area ...... 47 5.13.2 Identified system limitations...... 48 5.13.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects 48 5.14 North East Lake Macquarie load area ...... 49 5.14.1 Description of North East Lake Macquarie load area ...... 49 5.14.2 Identified system limitations...... 50 5.14.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects 50 5.15 North West Sydney load area ...... 51 5.15.1 Description of North West Sydney load area ...... 51 5.15.2 Identified system limitations...... 51 5.15.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects 52 5.16 Pittwater and Terrey Hills load area ...... 53 5.16.1 Description of Pittwater and Terrey Hills load area ...... 53 5.16.2 Identified system limitations...... 54 5.16.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects 55 5.17 Port Stephens load area ...... 56 5.17.1 Description of Port Stephens load area ...... 56 5.17.2 Identified system limitations...... 57 5.17.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects 57 5.18 Singleton Load area ...... 58 5.18.1 Description of Singleton load area ...... 58 5.18.2 Identified system limitations...... 59

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5.18.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects 59 5.19 St George load area ...... 60 5.19.1 Description of St George load area ...... 60 5.19.2 Identified system limitations...... 61 5.19.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects 61 5.20 Sutherland load area ...... 62 5.20.1 Description of Sutherland load area ...... 62 5.20.2 Identified system limitations...... 63 5.20.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects 63 5.21 Sydney CBD Load Area ...... 64 5.21.1 Description of Sydney CBD load area ...... 64 5.21.2 Identified system limitations...... 65 5.21.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects 65 5.22 Upper Central Coast load area ...... 66 5.22.1 Description of Upper Central Coast load area ...... 66 5.22.2 Identified system limitations...... 67 5.22.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects 67 5.23 Upper Hunter load area ...... 68 5.23.1 Description of Upper Hunter load area ...... 68 5.23.2 Identified system limitations...... 69 5.23.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects 69 5.24 Upper North Shore load area ...... 70 5.24.1 Description of Upper North Shore load area ...... 70 5.24.2 Identified system limitations...... 71 5.24.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects 71 5.25 West Lake Macquarie load area ...... 72 5.25.1 Description of West Lake Macquarie load area ...... 72 5.25.2 Identified system limitations...... 73 5.25.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects 73 5.26 Primary distribution feeder limitations ...... 73 6 TRANSMISSION LOAD AREAS ...... 74 6.1 Preliminary notes ...... 74 6.1.1 Changes in dual function asset status ...... 74 6.1.2 Dual function connection points...... 74 6.1.3 Inter-Network Impact ...... 74 6.2 Ausgrid System Total Maximum Demand Forecasts ...... 74 6.2.1 Dual function substation demand forecasts ...... 76 6.3 Transmission load area - Central Coast ...... 76 6.3.1 Description of Central Coast transmission load area ...... 76 6.3.2 Identified system limitations...... 77 6.3.3 Identified Feeder limitations changes from last year’s DTAPR - deferred or committed projects77 6.3.4 Changes in dual function asset status ...... 78 6.3.5 Dual function connection points...... 78 6.4 Transmission load area – Lower Hunter ...... 79 6.4.1 Description of Lower Hunter 132kV transmission load area ...... 79 6.4.2 Identified system limitations...... 80 6.4.3 Identified System limitations changes from last year’s DTAPR - deferred or committed projects81 6.4.4 Changes in dual function asset status ...... 81 6.4.5 Dual function connection points...... 81 6.5 Sydney Inner Metropolitan transmission load area ...... 81 6.5.1 Description of Sydney Inner Metropolitan transmission load area ...... 81 6.5.2 Identified system limitations...... 84 6.5.3 Identified Feeder limitations changes from last year’s DTAPR - deferred or committed projects87 6.5.4 Changes in dual function asset status ...... 87 6.5.5 Dual function connection points...... 87 6.6 Frequency control and load shedding ...... 88 6.7 Stability ...... 88

7 NETWORK INVESTMENTS ...... 89 7.1 Regulatory investment tests ...... 89 7.1.1 Completed during the year ...... 89 7.1.2 In progress during the year...... 90 7.1.3 For the forward planning period - Distribution ...... 92 7.1.4 Longer term constraints and indicative developments – Distribution ...... 93 7.1.5 For the forward planning period – Dual Function...... 95 7.1.6 Longer term constraints and indicative developments – Dual Function ...... 96 7.1.7 Not proceeding – Distribution ...... 97 7.1.8 Not proceeding – Dual Function ...... 97 7.2 Completed or cancelled investments ...... 99 7.2.1 Refurbishment, replacement or augmentations – Distribution ...... 99 7.2.2 Refurbishment, replacement or augmentations – Dual Function ...... 99 7.3 Committed investments ...... 100 7.3.1 Refurbishment, replacement or augmentations – Distribution ...... 100 7.3.2 Refurbishment, replacement or augmentations – Dual function ...... 117 7.3.3 Committed dual function augmentations ...... 118 7.4 Urgent and unforseen investments ...... 118 8 JOINT PLANNING ...... 119 8.1 Joint planning with TransGrid TNSP ...... 119 8.1.1 Process and methodology ...... 119 8.1.2 Joint TransGrid - Ausgrid planning completed in 2020 ...... 120 8.1.3 Planned joint TransGrid-Ausgrid network investments ...... 122 8.2 Joint planning with other DNSPs ...... 123 8.2.1 Process and methodology ...... 123 8.2.2 Joint Ausgrid and other DNSP planning completed in preceding year ...... 123 8.2.3 Planned DNSP joint network investments ...... 123 8.2.4 Additional information ...... 123 9 NETWORK PERFORMANCE ...... 124 9.1 Reliability measures and standards ...... 124 9.1.1 Supply reliability standards ...... 124 9.1.2 Network Supply reliability performance in the preceding year ...... 125 9.1.3 Service Target Performance Incentive Scheme (STPIS) ...... 128 9.1.4 Forecast of network reliability performance ...... 128 9.1.5 Compliance with network reliability standards ...... 129 9.2 Quality of supply standards ...... 130 9.2.1 Voltage range for supplied electricity ...... 130 9.2.2 Harmonics and total harmonic distortion ...... 130 9.2.3 Voltage fluctuations (Flicker) – Applicable quality of supply codes, standards and guidelines131 9.2.4 Voltage unbalance – Applicable quality of supply codes, standards and guidelines ...... 131 9.3 Quality of supply performance for preceding year ...... 131 9.3.1 Supply voltage performance ...... 131 9.3.2 Harmonic content of supply voltage waveform ...... 131 9.3.3 Voltage fluctuations (Flicker) performance ...... 131 9.3.4 Voltage unbalance performance...... 132 9.4 Corrective action planned to meet quality of supply standards ...... 132 9.4.1 Supply voltage ...... 132 9.4.2 Flicker, Harmonics and Unbalance ...... 132 9.5 Compliance with quality of supply standards ...... 132 10 ASSET MANAGEMENT...... 134 10.1 Ausgrid’s asset management approach ...... 134 10.2 Risk management strategies...... 134 10.2.1 Sub-transmission underground cable strategy ...... 134 10.2.2 11kV switchgear strategy ...... 135 10.2.3 Additional replacement programs ...... 136 10.3 Distribution network losses ...... 136 10.4 Obtaining further information on asset management ...... 136 11 DEMAND MANAGEMENT ...... 137 11.1 Demand management ...... 137 11.2 Demand management considerations in 2020 ...... 138 11.3 Demand management activities in 2019-20 ...... 138 11.3.1 Demand management projects initiated in 2019-20 ...... 138 11.3.2 Demand management projects implemented in 2019-20 ...... 139

11.3.3 Demand management innovation ...... 139 11.4 Forecast demand management projects ...... 150 11.5 Demand side engagement ...... 150 11.6 Embedded generator enquiries and connection applications ...... 150 12 INVESTMENTS IN INFORMATION TECHNOLOGY AND COMMUNICATION SYSTEMS ...... 151 12.1 Information, Communication and Technology ...... 151 12.1.1 ICT investment actual 2019/20 and forecast ...... 152 12.2 Advanced Distribution Management System (ADMS) ...... 153 12.2.1 ADMS Benefits ...... 153 12.2.2 ADMS Program Implementation ...... 154 12.3 Network Asset Digitisation ...... 155 12.3.1 Network Asset Digitisation Benefits ...... 155 12.3.2 Network Asset Digitisation Program Implementation ...... 155 ANNEXURE A – GLOSSARY ...... A ANNEXURE B – RELIABILITY AND PERFORMANCE LICENCE CONDITIONS ...... B ANNEXURE C – COMPLIANCE CHECKLISTS...... C

1 Executive Summary

Ausgrid is both a registered Distribution Network Service Provider and a Transmission Network Service Provider, and is required to produce a Distribution Annual Planning Report (DAPR) covering its distribution network and a Transmission Annual Planning Report (TAPR) covering its transmission (dual function asset) network. To align the publication of the DAPR and TAPR, the National Electricity Rules (NER) permit the publication of both documents in a combined annual planning report. This Distribution and Transmission Annual Planning Report (DTAPR) presents the results of Ausgrid’s annual planning review of both its distribution and transmission (dual function asset) network conducted since the publication of the previous DTAPR in December 2019. The objective is to: • Provide transparency to Ausgrid’s decision making processes to assist non-network providers, other Network Service providers and connection applicants to make efficient investment decisions • Provide information on Ausgrid’s distribution assets planning process, including forecasting, identification of network limitations, and the development of potential credible options to address these limitations covering a minimum five year forward planning period • Report on the results of Ausgrid’s annual planning review, including subtransmission substation (STS), zone substation (ZS) and subtransmission feeder forecast loading, identified network limitations including capacity, asset condition and other limitations on the subtransmission and distribution assets; and the potential credible solutions to address these limitations • Provide third parties the opportunity to offer alternative proposals to the identified network needs, including non-network solutions such as demand management or embedded generation • Provide timely indication of the planned commencement dates for the assessment of proposed projects that will be subject the Regulatory Investment Test for Distribution • Provide information on Ausgrid’s demand management activities and actions taken to promote non-network initiatives each year, including plans for demand management and embedded generation over the forward planning period, and • Describe significant changes to identified network limitations including capacity, asset condition and other limitations on the network assets; changes to potential credible solutions, and project deferrals and cancellations. The DAPR section covers a minimum five year forward planning period and the TAPR section covers a ten year forward planning period from December 2020. Online data associated with the 2020 DTAPR, as well as the document itself, is accessible via Ausgrid’s website: www.ausgrid.com.au/DTAPR

2 Introduction

This Distribution and Transmission Annual Planning Report (DTAPR) has been prepared to comply with National Electricity Rules (NER) clause 5.13.2 “Distribution Annual Planning Report” (DAPR), and clause 5.12.2 “Transmission Annual Planning Report” (TAPR). Version 146 of the NER has been used. Ausgrid has prepared this DTAPR with a five year forward planning horizon. It reflects the outcomes of the annual planning review of Ausgrid’s electricity network since the publication of the December 2019 DTAPR. The purpose of this document is to inform Registered Participants, stakeholder groups and interested parties of the identified future network needs, the committed and proposed solutions to these needs and the potential opportunities for non-network solutions, particularly for large investments where the Regulatory Investment Test for Distribution (RIT-D) applies. Ausgrid’s DTAPR has been prepared to meet the requirements of the National Electricity Rules Schedule S5.8 Distribution Annual Reporting Requirements to: • Provide transparency to Ausgrid’s decision making processes and assist non-network providers, other Network Service providers and connection applicants to make efficient investment decisions • Promote efficient investment decisions in the electricity market • Include information on the planning process including forecasting, identification of network limitations, and the development of potential credible options to address these limitations • Set out the results of Ausgrid’s annual planning review, including joint planning with other Network Service Providers, covering a minimum five year forward planning period for distribution assets • Give third parties the opportunity to offer alternative proposals to the identified network needs, including non-network solutions such as demand management or embedded generation • Inform Registered Participants and interested parties on the outcomes of the annual planning review, including network capacity and load forecasts for subtransmission lines, zone substations and transmission- distribution connection points, and any 11kV primary distribution feeders which are constrained or are forecast to be constrained within the next two years • Provide information on Ausgrid’s demand management activities and actions taken to promote non-network initiatives each year, including plans for demand management and embedded generation over the forward planning period. Ausgrid also owns, develops, operates and maintains transmission dual function assets in NSW. Although these dual function assets form part of our distribution network they are operated in parallel with TransGrid’s network, and essentially perform a transmission function by supporting the main NSW transmission network. Ausgrid is therefore also registered as a TNSP and is required to publish a Transmission Annual Planning Report (TAPR) covering our dual function assets. The NER permit Ausgrid to publish its TAPR as part of the DAPR to align the publication of both reports each year. Ausgrid has combined the two reports into one Distribution and Transmission Annual Planning Report. 2.1 About Ausgrid Ausgrid’s network is a shared asset that has powered the lives of our customers and their communities for over a century. Our network is made up of large and small substations connected through high and low voltage powerlines, underground cables and power poles spread across more than 22,275 square kilometres. Our network extends from Waterfall in Sydney’s south, to Auburn in inner western Sydney, to the Central Coast and Hunter Valley. Today, we support over 20 percent of the national gross domestic product and serve over 4 million people in almost 1.8 million homes and businesses. Our core business is to provide distribution network services to our customers. We do this by building and operating assets and delivering non-network solutions to ensure safe and reliable access to electricity at an efficient and reasonable price. As technology evolves, our customers’ needs and expectations are changing. Many households, communities and businesses now expect to generate, consume and sometimes store their own electricity and sell any excess back into the grid. The grid has a pivotal role in supporting customers during this transition. We are committed to working with our customers and stakeholders to realise this lower carbon future at the lowest possible cost. 2.1.1 Our purpose and vision Our Vision is to become a leading energy solutions provider, recognised both locally and globally.

Our Purpose is to connect communities and empower lives with a focus on affordability, reliability and sustainability Our Values guide the standard of behaviour expected of Ausgrid and our employees. These following values form the basis for everything we do: • Work Safe, Live Safe • Customer-focused • Commercially minded • Collaborative • Honest • Accountable, and • Respectful. 2.1.2 Our operating environment Ausgrid is regulated by statutory and legislative requirements, including Work Health and Safety (WH&S), environmental, competition, industrial, consumer protection and information laws, National Electricity Regulation (detailed below), and the NSW Electricity Supply Act 1995 (ESA). We must also comply with the conditions of our NSW Distribution Network Service Provider licence (under the ESA). The National Electricity Regulation is primarily represented by the National Electricity Law (NEL) and National Electricity Rules (NERs) which regulate the National Electricity Market, and the National Energy Customer Framework. Ausgrid operates in the National Electricity Market (NEM) as both a distribution and transmission network service provider (DNSP and TNSP). The National Electricity Objective (NEO), as stated in the National Electricity Law is to: “promote efficient investment in, and efficient operation and use of, electricity services for the long term interests of consumers of electricity with respect to: (a) price, quality, safety, reliability and security of supply of electricity; and (b) the reliability, safety and security of the national electricity system.” We meet these obligations with investments that address our customers’ requirements for safe, affordable, reliable and sustainable network services. We manage compliance with these laws and regulations through our internal codes and policies and a common control framework. This control framework comprises plans, policies, procedures, delegations, instruction and training, audit and risk management. On 4 June 2015, the Electricity Network Assets (Authorised Transactions) Act 2015 and the Electricity Retained Interest Corporations Act 2015 were enacted. The legislation allowed the NSW Government to deliver its policy to lease 49 percent of the state's electricity networks and to use the proceeds from those transactions to build new infrastructure. This lease agreement was completed on 1 December 2016. Since that time Ausgrid has been managed as a Network Asset & Operator Partnership with the majority share (50.4%) held by AustralianSuper & IFM Investors and 49.6% held by the NSW Government.

2.2 Ausgrid’s network In 2019/20, Ausgrid’s network supplied electricity to almost 1.8 million network customers. Our distribution area (Figure 2.1) covers an area of 22,275 square kilometres and includes some of the most densely populated and fastest growing areas of NSW. We supply customers as far north as the Upper Hunter Valley, as far south as Waterfall and to Auburn in Sydney’s west.

Figure 2.1: Ausgrid’s network area

2.2.1 Number and types of network assets Ausgrid’s subtransmission and distribution network includes: • A dual function subtransmission system of 132kV assets (these are transmission assets which support the main TransGrid transmission system); • A subtransmission system of 33kV, 66kV and 132kV assets; • A high voltage distribution system of predominantly 11kV, with some 5kV, 22kV and 33kV and 12.7kV Single Earth Wire Return assets; and • A low voltage distribution system of 400V assets (230V single phase).

Table 2.1: Ausgrid network statistics

Network Asset 2019/20 Dual function (Transmission) System – 132kV (km) 958 Sub-transmission System - 33kV, 66kV and 132kV (km) 3,018 Substations - Sub-transmission (STS) 47 Substations - Zone (ZS) 183 Substations - Distribution 32,802 High Voltage Overhead (km) 10,011 High Voltage Underground (km) 8,571 Low Voltage Overhead (km) 18,397 Low Voltage Underground (km) 7,879 Feeder Numbers CBD 59 Feeder Numbers Urban 1,901 Feeder Numbers Short Rural 383 Feeder Numbers Long Rural 5 Pole (number) 512,126 Streetlights (number) 255,025

NOTES: • Distances for overhead and underground lines are circuit km. • Asset counts and lengths do not include private assets. • Low voltage overhead and underground lengths also includes streetlighting. For the 2019/20 financial year, length of OH streetlighting mains is 5,315km, length of UG streetlighting cable is 1,217km.

Figure 2.2: Typical components of an electricity network

2.3 Annual planning review 2.3.1 Distribution The National Electricity Rules (Version 124) require that the annual planning review includes the planning for all assets and activities carried out by Ausgrid that would materially affect the performance of its network. This includes planning activities associated with replacement and refurbishment of assets and negotiated services. The objective of the distribution annual planning review is to identify possible future issues over a minimum five year planning horizon that could negatively affect the performance of the distribution network to enable DNSPs to plan for and adequately address such issues in a sufficient timeframe. This document provides information to Registered Participants and interested parties on the nature and location of emerging constraints on Ausgrid’s subtransmission and 11kV distribution network assets, commonly referred to as the distribution network. The timely identification and publication of emerging network constraints allows the market to identify potential non-network options and Ausgrid to develop and implement appropriate and timely solutions. 2.3.2 Transmission The NER require network service providers, who own and operate dual function assets to register as Transmission Network Service Providers by virtue of the definition of 'TNSP' in the rules. Certain parts of the rules treat dual function assets in the same way as other subtransmission assets. However, for the purposes of the transmission annual planning review and reporting, dual function assets are treated as transmission assets requiring a Transmission Annual Planning Report. For the purposes of economic evaluation and consultation with Registered Participants and Interested Parties, dual function assets are treated as distribution network assets and are subject to the same economic evaluation test. Ausgrid’s dual function network is defined as those assets with a voltage of 66kV and above that are owned by Ausgrid, and operate in parallel with and provide material support to the TransGrid transmission network. These assets may either operate in parallel with the transmission network during normal system conditions or can be configured so that they operate in parallel during specific system conditions. 1 An asset is deemed to provide material support to TransGrid’s transmission network if:

• there is otherwise limited or no system redundancy within the transmission network, or • investment in the transmission system would be required within the regulatory period if that network asset did not exist, or • the feeder provides operational support to the transmission network (e.g. to facilitate maintenance of transmission assets or improve security of supply) and the asset provides an effective parallel with the transmission network via a relatively low impedance path. Ausgrid reviews the function of its dual function assets annually to determine if they continue to provide material support to TransGrid’s transmission network. This review is used as input for preparing Ausgrid’s regulatory reporting, the regulatory submission, and pricing methodology. For the purpose of AER Revenue Determination submissions, the list of dual function assets is determined based on the forecast load and the system configuration as at the beginning of the regulatory period. 2.3.3 Distribution and Transmission Annual Planning Review and Reporting Reporting of both planning reviews have been merged into one document. The information that the NER requires Ausgrid to report for both distribution and transmission is covered throughout the various sections of the DTAPR. 2.4 Ausgrid’s planning approach The network planning and development process for both the distribution and transmission networks is carried out in accordance with the NER Chapter 5, Part D, Network Planning and Expansion. Planning for distribution and subtransmission assets is carried out in accordance with NER 5.13.1 - Distribution annual planning review and NER 5.12.1 - Transmission annual planning review for dual function assets.

1 Network Planning Standard NIS433: Classification of Dual-Function Assets

2.4.1 Investment objectives and decision criteria Ausgrid’s investment objectives respond to one or more of three key policy directives: • Comply with its obligations under Chapter 5 of the NER; the Licence conditions for the operator of a transacted distribution system, as part of the Distributor’s Licence granted to Ausgrid Operator Partnership2, and other applicable regulatory instruments; • Manage business risks with particular regard to ensuring the safety of its employees, customers and the broader community; maintaining the reliability of supply to its customers; and protecting the environment; and • Improve the efficiency of the business or produce an affordable and sustainable supply of energy to the community. The following table, taken from Ausgrid’s Network Development and Planning Strategy, provides a summary of these objectives:

Reliability Ensuring network development and the integration of customer connections allows for reliability standards to be maintained in accordance with Ausgrid’s asset management objectives. This means: - Meeting corporate objectives for STPIS outcomes; - Complying with licence conditions for reliability performance at feeder category and individual feeder level; and - Deliver network performance that customers are prepared to pay for. Safety Planning the network to support the elimination of safety incidents so far as reasonably practicable or reduce risks to be as low as reasonably practicable consistent with Ausgrid’s Electricity Network Safety Management Plan (ENSMS). This includes: - Undergrounding where appropriate; - Minimising bushfire risk and exposure by selecting appropriate line routes and

construction; and - Configuration of assets to minimise worker exposure (e.g. through redundancy or interconnectivity) to risk (e.g. isolators and interconnectivity to allow electrical isolation of assets for work.). Affordable & Sustainable - Utilising cost benefit analysis to assess feasible options including demand management to deliver network performance objectives at least cost. - Use long term planning to manage long life cycle assets by considering changes in operating requirements over the lifespan of the assets.

To provide a sound and consistent approach, decisions to invest are made based on (as appropriate): • Clearly defined requirements in terms of legislative obligations and identified risks; • Compliance with Ausgrid’s policies and standards; • Sound risk assessment (safety, unserved energy, environmental, financial, community impact); • Consideration of whole-of-life costs and benefits and the time-value of money; • Consideration of the range of feasible solutions without bias for technology; and • A level of analysis which is commensurate with the costs and risks. In compliance with the requirements of the National Electricity Objective and various elements of the NER, investments in the network are made on the basis of best economic value to all producers and consumers of electricity in the NEM. Network investment options are selected where they deliver the highest Net Present Value (NPV), taking into account the costs, risks and anticipated benefits.

2 Refer to Annexure B - Licence conditions for the operator of a transacted distribution system, part of the Distributor’s Licence granted to Ausgrid Operator Partnership (with Ministerial variations, dated December 2017 and February 2019). The licence conditions can also be viewed at: https://www.ipart.nsw.gov.au/Home/Industries/Energy/Energy-Networks-Safety-Reliability-and-Compliance/Electricity-networks/Licence- conditions-and-regulatory-instruments

Ausgrid’s investment processes are designed to promote: • Efficient and prudent investments consistent with its stated investment objectives; • Timely identification of the business’s capital and resource requirements; • Investment decisions that are informed by a full understanding of the costs, benefits and regulatory requirements and are authorised in accordance with the business’s internal delegations policy; • Compliance with statutory and regulatory obligations to the Board, stakeholders, shareholders, broader community, regulators and appointed auditors; • Co-ordination with related organisations, including other network service providers and utilities; • Investment opportunities being prioritised to best meet the objectives of the corporation and reviewed at Board level; and • A sustainable investment profile over the long term, to minimise peaks and troughs that can lead to instability in electricity prices. 2.4.2 Network planning process Ausgrid follows a structured planning process that can be summarised by the following diagram from our Network Investment Policy. The planning phase involves identifying the investment needs and risks; developing one or more options to address these needs; assessing costs and benefits associated with those options to select the preferred option and initiating the preferred option.

Planning Phase

Forecast Plans

Identify Existing Develop Investment Design & Needs & Initiate Manage Retire Network Options Appraisal Build Risks

Investment Objectives

Figure 2.3: Ausgrid planning process

The timeframe and complexity of this process varies according to network level, risk profile, and the project scale and intent. Accordingly, Ausgrid organises its planning activities by distinct investment categories. This approach allows Ausgrid to adopt a level of analysis and justification that is commensurate with the costs, risks and obligations associated with each investment category discussed below: Major projects These are generally major subtransmission investments designed to meet the various needs of the network, in particular demand growth, voltage, supply quality, fault duty, stability and asset renewal requirements. Investment options are identified by a cost-benefit analysis within an Area Planning framework to meet the requirements of large geographic areas over a 20 year planning period. Given that these projects are generally of significant value, this process involves detailed analysis of a number of alternatives. In cases where the need is specific to a particular facility or asset, these requirements can be met by a specific planning study to update the area plan. Asset replacement and network risk These investments are designed to manage risks associated with asset conditions and the safe and reliable operation of the network. Investment is either to meet specific obligations and standards; or justified based on an assessment of cost and benefits, in terms of risk mitigated (e.g. determined from condition assessments and historical performance). Investments usually involve programmes of work that generally comprise larger volume of smaller projects designed to address the risks associated with assets of a similar type.

Distribution (generally 11kV) These investments address the needs of the distribution network, in particular demand growth, voltage, supply quality and fault duty requirements. These investments are planned to meet the requirements of the distribution network over a five year planning horizon. The level of analysis depends on the scale and complexity of individual projects. Customer connections These investments are for the reinforcement of the up-stream portion of the shared network associated with connections that are not customer funded. Investments are initiated by customer connection applications. Investment requirements are forecast on the basis of historical expenditure trends adjusted for changes in Ausgrid’s connection policy. Reliability These investments address gaps in reliability performance that will not be met by the other investment categories. Proactive investments are planned to respond to forecasts of reliability performance considering investments planned under other investment categories; and reactive investments are determined through an assessment of reliability outcomes based on actual performance. 2.4.3 Network area plans To ensure Ausgrid’s investment is prudent and efficient, our planning of major investments in the network: • is based on meeting the requirements of geographic areas, defined on the basis that they represent discrete electrical areas and with relative independence from network interconnections; • considers Ausgrid’s obligations under the NER and other applicable regulatory instruments in a holistic manner; and • considers identified needs over a twenty year planning horizon to allow for the development of a long term strategy that addresses various drivers and minimises long term cost. Ausgrid’s plans are documented in ‘Area Plans’, covering the identified network needs, potential credible options and the preferred solution for each geographic area. For the purposes of planning investments to meet the needs of the subtransmission network, Ausgrid has divided its network into geographic ‘Areas’ and generates an ‘Area Plan’ for each geographic ‘Area’. The requirements of the Ausgrid 132kV network that links TransGrid’s bulk supply points to Ausgrid’s subtransmission network are considered based on the broader Sydney Inner Metropolitan, Central Coast and Lower Hunter regions to create three ‘Transmission Area Plans’. Each of these regions encompasses multiple ‘Areas’. Projects that comprise the preferred strategy for each Area Plan are determined by cost-benefit analysis and entered in the Major Project List (Project List) with each project initiated based on this list and on expected project lead times, and in accordance with Ausgrid’s Investment Initiation Standard. The Project List records the identified system limitation and need date, the required completion date and the estimated cost for each project. The Area Plans are reviewed on approximately a five year basis. In order to optimise project implementations, the identified need date of projects within the Major Project List is reviewed annually as new information and forecasts become available. Any changes to the projects within the Project List are recorded and supported by planning reports which include the reason for the change. This Project List also forms the basis of the economic assessment, consultation and reporting requirement under the RIT-D. 2.5 Significant changes from previous DTAPR Significant changes from the previous DTAPR report are covered in the various sections of the DTAPR and explain the reasons for project cancellations or deferment beyond the 5 year planning horizon for distribution and 10 years for transmission. The structure of the 2020 DTAPR and associated data files are similar to those of the 2019 DTAPR and associated data files. 2.6 Distribution System Limitations Template – Online Data A requirement introduced in 2017 is clause 5.13.3 of the NER, whereby Ausgrid is required to publish online data in the format prescribed by the Australian Energy Regulator (AER) in a Distribution System Limitation Template. In keeping with the principle expressed by the AER that data should be provided in a more analysis friendly format than lengthy PDF documents, other key data tables have also been provided online so that they can be downloaded by interested parties.3

3 Reference AER Final Decision – Distribution Annual Planning Report Template V1.0, June 2017, pages 1-3 and 1-4.

Following the release of the TAPR guidelines in December 2018, we populated a Transmission System Limitation Template for the first time in 2019 and this is included again this year. Online data associated with the 2020 DTAPR, as well as the document itself, is accessible via Ausgrid’s website at www.ausgrid.com.au/DTAPR

3 Forecasts for the forward planning period

3.1 Data tables online In keeping advice from the AER, that data should be made accessible in a format that can been readily interrogated, forecast and related data tables are published online and can be accessed via Ausgrid’s website at www.ausgrid.com.au/DTAPR Table definitions for the ‘Substation capacity and demand forecast’ table and the ‘Dual Function asset 10 year demand forecast’ table located on Ausgrid’s website are as follows:

Substation capacity and demand forecast table definitions Heading Label Description Area Plan An area as defined by Ausgrid used to describe a collection of substations of similar geographical region Substation Name of the substation. Details on the primary and secondary voltages of the substation included in the name to differentiate some locations of similar naming convention Substation Type Denotes either Zone Substation (ZS) or Subtransmission Substation (STS) Total Capacity Maximum load able to be carried by the substation with all elements in service. A summer (MVA) and winter Total Capacity value is provided Firm Capacity Load able to be carried by the substation with the largest rated element out of service. A (MVA) summer and winter Firm Capacity is provided Load Transfer Amount of load that can be restored in the event of a whole zone outage by switching the Capacity (MVA) distribution network. The transfer capacity assumes that a single zone is rendered out of service and the rest of the network is in system normal configuration. A summer and winter Transfer Capacity is provided 95% Peak Load The number of 15 minute occurrences that exceeded the 95th percentile value of Exceeded maximum demand was summed and divided by four to determine the "hours within 95% (hrs/yr) of peak" value. A summer and winter 95% Peak Load exceeded value is provided Embedded The Solar PV capacity by zone substation is consistent with the information used in the Generation - forecast and is current as at March 2020 and includes all known systems. The solar Solar PV (MW) generation capacity is based on information gathered from the application for connection forms completed at the time of applying for a solar installation and recorded in the Distributed Energy Resources Register Embedded Embedded generation “Other” includes all known diesel, landfill biogas, coal seam Generation - methane, natural gas including tri-generation and co-generation, hydro and mini hydro, Other (MW) coal washery, and waste heat recovery generating units known to Ausgrid. Not all of these units export to the grid as they are not capable of operating in parallel with the Ausgrid network and are intended for standby operation in island mode. Actual Load Recorded peak demand for the substation. A summer and winter actual is provided (MVA) Actual Load Recorded power factor for the substation at time of peak load. The value is compensated (PF) and takes into account the actual switching of capacitors at the substation at time of peak load. A summer and winter actual is provided Forecast Load POE50 medium scenario planning forecast peak demand in MVA for each respective (MVA) forecast year for the substation. A summer and winter actual is provided Forecast Load Forecasted power factor as calculated from POE50 medium scenario planning forecast (PF) for each respective forecast year for the substation. The value is compensated and takes into account the forecasted switching of capacitors at the substation for any given forecast year. A summer and winter actual is provided

Dual Function asset 10 year demand forecast table definitions Heading Label Description Substation Name of the substation. Details on the primary and secondary voltages of the substation included in the name to differentiate some locations of similar naming convention Substation Type Denotes either Zone Substation (ZS) or Subtransmission Substation (STS) Substation Recorded peak demand in MW for the substation. A summer and winter actual is provided Actual MW Substation Recorded peak reactive load for the substation. The value is compensated and takes into Actual MVAr account the actual switching of capacitors at the substation at time of peak load. A summer and winter actual is provided Substation POE50 medium scenario planning forecast peak demand in MW for each respective Forecast MW forecast year for the substation. A summer and winter actual is provided Substation POE50 medium scenario planning forecast peak reactive load in MVAr for each respective Forecast MVAr forecast year for the substation. The value is compensated and takes into account the forecasted switching of capacitors at the substation for any given forecast year. A summer and winter actual is provided

3.2 Zone and Subtransmission substation load forecasting methodology This section describes the maximum demand planning forecasting methodology (the forecast) used by Ausgrid for zone substations and subtransmission substations. The forecasts of peak demand are prepared at the zone substation level and at the subtransmission substation level. These spatial forecasts form a key input into the planning of Ausgrid’s capital expenditure program. The underlying forecast is constructed from two primary components; a near term forecast that is based on the statistically derived trend line of the weather corrected historical customer electricity demand, and a medium to long term forecast that is based on a system level econometric model. This recognises the need for the forecast model to consider the short-term trend and long-term macro econometric factors. Both components are adjusted for out of trend impacts from embedded generation, energy storage, electric vehicles and energy efficiency. Adjustments to the forecast are also made at a spatial level to account for planned new large customer connections and planned changes to the network architecture such as load transfers. The forecast is prepared seasonally for summer and winter. In the early months of 2020, the spread of COVID-19 reached pandemic proportions and governments mobilised measures to respond to health risks which impacted demand. To account for this event, additional forecast demand adjustments and methodology changes were made to the near-term period of the 2020 forecast. 3.2.1 Spatial trend component of forecast The near-term component of the forecast is based upon the local historical trend in total customer demand from both grid supplied electricity and customer embedded generation. The process for deriving the local substation forecast is as follows: a) Raw metered electricity demand data is obtained for zone substations and subtransmission substations for 7 years at 15min intervals. b) 10 years of weather data is obtained from the Bureau of Meteorology for weather stations across Ausgrid’s network area. Each zone and subtransmission substation is assigned a representative Bureau of Meteorology weather station. c) Network configuration data is obtained from Ausgrid’s planning and customer connections groups. d) The metered grid supplied electricity demand data is cleansed to remove abnormal loads (generally resulting from temporary network switching and abnormal configurations). This prevents abnormally switched loads from distorting historical trends. e) The total customer electricity demand is then weather corrected based on the variable of “average ambient temperature” and subjected to Monte Carlo simulation analysis. This enables calculation of probability of exceedance (POE) levels. f) Embedded generation demand for all 30 min intervals is modelled from a representative sample of customer interval meter data (gross metered systems) for customer solar power systems. The historical non- dispatchable embedded generation (30 min intervals) at each zone substation is derived from the embedded generation demand model and historical customer connection information. The embedded

generation is then added to the weather corrected grid supplied electricity demand data to derive the customer electricity demand. g) Maximum demand impacts from historical block loads are then identified from planning information and actual network system meter data for the historical time series. These block loads comprise all customer connections which result in a step change in demand at the zone substation. The basis for including or excluding block loads is described in section 3.2.3.8 below. These step changes to maximum demand are then reversed from the customer electricity demand data to derive the underlying customer electricity demand data series. h) By excluding step changes due to larger, lumpy customer loads and including the electricity supplied by customer generation, a more stable underlying trend of customer demand is revealed. i) Regression of the resultant data series calculates the underlying rate of growth using a line of best fit at each zone and subtransmission substation. Any step changes in demand (solar, historical block loads and load transfers) are then reinserted to arrive at the starting point. j) This local substation trend forms the basis for the first 2 years and is a component of years 3 and 4 of the forecast. k) Note that the historical trend for the 2020 forecast has not been impacted by the effects of COVID-19 health response measures as these measures were implemented after the 2019/20 summer period 3.2.2 System level econometric model component of forecast The medium to long term component of the forecast is based upon a system level econometric model. The econometric model is derived from key drivers at the local and system total level for both residential and non- residential elements. The process for deriving the econometric component of the forecast is as follows: a) The residential and non-residential components of the econometric model include both price and income response elements. The residential component includes drivers for the change in real retail residential electricity prices and the change in real average household disposable income. The non-residential component includes drivers for the change in real retail non-residential electricity prices and the change in NSW Gross Value Added Services. The residential component also includes impacts from any forecast changes in population growth. b) Forecast variation in real retail residential electricity prices, real average household disposable income, real retail non-residential electricity prices and NSW Gross Value Added Services are obtained. For the 2020 forecast, this data was obtained from the Australian Energy Market Operator (AEMO) and is the data used for AEMO’s 2020 Electricity Statement of Opportunities (ESOO). Due to an improved regression fit, NSW Gross Value Added Services replaced NSW Gross State Product as the income explanatory variable in the 2020 non-residential demand regression model c) Due to the collinearity of the historical customer price response with historical impacts from energy efficiency improvement, the model is based upon the total ‘electricity services‘ to customers. The ‘electricity services’ includes the total metered demand (grid supply), the historical demand impacts from embedded generation and the historical demand impacts from Commonwealth and New South Wales government energy efficiency programs. d) The total metered electricity demand (grid supply) is obtained for all 30 min intervals from the bulk supply point meter data for Ausgrid’s network. e) From the interval metered data for over 500,000 customers and the total system metered electricity demand data from the bulk supply point meters, a regression model is used to calculate the separate metered electricity demand for residential customers and non-residential customers. f) The historical demand impacts from non-dispatchable embedded generation are obtained as per item f in the description of the spatial trend forecast above. These are allocated separately for residential and non- residential customers. g) The historical and forecast demand impacts from Commonwealth and New South Wales government energy efficiency programs are obtained for three key programs: i. the Minimum Energy Performance Standards (MEPS) program which sets national minimum energy performance standards for electrical appliances such as air conditioners, motors, televisions and refrigerators; ii. the Building Code of Australia (BCA) which sets minimum energy performance standards for buildings; and iii. the NSW Energy Savings Scheme (ESS) which encourages customers to invest in energy efficiency improvements in their homes and businesses. iv. The NSW Government has published the Energy Security Target and Safeguard Consultation paper. This paper details plans to expand the Energy Savings Scheme and introduce a new Peak demand reduction scheme. Estimates of the impact from the proposed scheme have been included.

Ausgrid obtains the historical and forecast demand impacts for these energy efficiency programs principally from external expert advice. The demand impacts are allocated separately for residential and non- residential customers. The peak demand contribution is derived from the seasonal daily load factor on day of system peak. h) The historical ‘electricity services’ for residential customers and the ‘electricity services’ for non-residential customers are then regressed against the separate independent variables of price and income. The econometric model determines the elasticities for both income and price for each of the residential and non- residential customer sectors. i) Following derivation of the econometric elasticities, historical embedded generation and energy efficiency impacts are reversed out to return to the starting point. This process excludes effects likely to pollute the relationship between grid supplied electricity demand and the price and income variables. The forecasted demand impacts due to changes in price and income over time is derived by the application of the econometric elasticities to econometric forecasts for future electricity price and income supplied by AEMO and as used in AEMO’s 2020 Electricity Statement of Opportunities (ESOO). j) Impacts due to new block loads, embedded generation, battery storage systems, energy efficiency, and electric vehicle take-up by customers are included as post model adjustments to the econometric model. k) The impacts from household energy (battery) storage and rooftop solar, or distributed energy resources (DER), in the 2020 maximum demand forecast are based upon a model originally developed from external consultancy advice. The model calculates annual electricity bill savings for representative customer types to derive likely uptake rates for DER across the Ausgrid network. In conjunction with modelled price paths for rooftop solar and batteries, an ROI is calculated for each representative customer type over time, which in turn drives the uptake of DER. Spatial allocation of the DER is based on the current allocation of the representative customer types across the Ausgrid network area and their respective DER projections from the model, aggregated to the zone substation level. Initial DER forecast years blend from historical DER trends to model outcomes over a 5 year period l) The impact from electric vehicles (EV) has been guided by information obtained from AEMO in mid-2019 and external consultancy advice. Demand impacts are derived using 5 charging typology types (Bus, Fleet, Residential, Carpark, and DC fast charge) which are allocated spatially using “points of interest” data along with NSW vehicle registration data for electric vehicles obtained from NSW Roads and Maritime Services, the 2019 ABS vehicle census by postcode data, and ABS 2016 census LGA income statistics. m) The residential component includes impacts from forecast changes in population growth based upon data from the NSW Department of Planning and ABS population projections. The population projections data from the NSW Department of Planning extracted from 2018. n) Each component is allocated at a zone substation level. Allocation of embedded generation and energy storage is based upon the current penetration of rooftop solar and DER model outputs. Allocation of energy efficiency impacts is based upon each substation’s share of annual metered electricity volume. Allocation of impacts due to population changes is based upon the 2018 NSW Department of Planning data at the Local Government area level, adjusted for the substation service boundaries. o) This econometric model forms the basis for years five and beyond of the forecast for each substation and a component of years 3 and 4 of the forecast. p) Adjustment to blending as described in point (o) above was undertaken for the application of income elasticities in the 2020 forecast to account for econometric impacts forecasted to occur in the near-term trend due to COVID-19 that are not covered by the local historical substation trend. Income econometric impacts are applied in full in years 1 and 2 of the forecast, reverting back to comprising a component of years 3 and 4, and returning to the basis of demand trends from years five and beyond. 3.2.3 Assumptions applied to substation load forecasts 3.2.3.1 Endeavour supplied substations There are three Ausgrid zone substations not supplied from within Ausgrid’s network but supplied from Endeavour Energy at 66kV and 33kV. These zone substations are Epping 66/11kV, Leightonfield 33/11kV and Hunters Hill 66/11kV. Demand from these zone substations is included in the aggregate data. Note, in 2018 a project was committed which will see 2 more zone substations be supplied from Endeavour Energy at 33kV. From 2020/21 both Auburn 33/11kV and Lidcombe 33/11kV zone substations will be supplied from Camelia STS in the Endeavour network area. Demand from these zone substations will remain as being included in the aggregate data. 3.2.3.2 Customer negotiated capacity Where a customer has negotiated a higher standard of service than the default planning standard and the agreed financial terms have been met, the substation load forecast is adjusted accordingly so that this capacity is reserved for that customer.

If a customer has negotiated a lower standard of service (e.g. to reduce their costs), this is generally not incorporated into the forecast. Generally, these requests are considered during network planning, or inherent in the connection of the customer. 3.2.3.3 Embedded generation The historical load data includes the impact of downstream embedded generation that was generating at the time of peak, consequently, the forecast includes the impact of non-dispatchable small scale generation such as rooftop solar installations. Where a generator has a material impact on peak load that is not accurately reflected in the historical data and information is available about generator output and reliability, the forecast is adjusted to reflect the expected impact of the generator, taking into account:

• the historical reliability of the generator and expectations about its future reliability, including weather dependency where relevant; • when the generator was installed and whether it is a temporary or permanent installation; • contractual obligations for Ausgrid to provide backup or standby supply to a site; and • network support agreements with the generator. Larger generators that are relied on for network support are generally included as a negative block load. In determining whether a generator is ‘large’, Ausgrid uses the same approach as is used for block loads and transfers. 3.2.3.4 Capacitors for power factor correction Reactive compensation for locations with known capacitor installations is modelled according to the following guidelines: • Growth rates are applied to the uncompensated MVAr component of load prior to switching in Ausgrid capacitors. In other words, growth rates are not applied to capacitors. • The amount of reactive compensation for forecast years is applied according to the nameplate step size and maximum available MVAr capacity and the application of 2 adjustment factors, the voltage adjustment factor and the operational adjustment factor. • The voltage adjustment factor calculated at 0.84 accounts for the difference between the nameplate rated voltage and the operational voltage at the corresponding substation. The voltage adjustment is the square of the ratio of nominal operational secondary voltage at the substation over the nameplate rated voltage of the capacity i.e. (11/12kV)² or (33/36kV)². • The operational factor accounts for the fact that capacitors are not necessarily switched in to maximise power factor. In determining the operational factor, historical patterns of capacitor switching are used. 3.2.3.5 Weather correction Historical loads are weather corrected, to enable statistical trend line calculation of growth rates and the determination of probabilistic forecast loads. The weather correction factor is the percentage difference between the weather corrected and actual load in the most recent historical year. This correction factor can be negative, positive or zero. Weather correction is applied according to the following rules: Maximum demands are weather corrected with a probability of exceedance of 50% (POE50) which forms the basis for planning decision-making.

• Each substation uses 10 years of Bureau of Meteorology (BOM) data from the geographically closest BOM weather station; • Ambient temperature is used; and • Weather correction is applied using a Monte-Carlo simulation method to determine the POE50 maximum demand. The simulation incorporates non-working days to model the effect of substations that can peak on a non-workday. 3.2.3.6 Exceptions for weather correction Weather correction is not applied to zone substations or subtransmission substations where the load does not exhibit weather dependency for that season, or where the load exhibits weather dependency that does not follow the general trend expected for that season based on an examination of the seasonal load versus temperature relationship. Weather correction is not applied to dedicated large customer loads (connected at the subtransmission level). 3.2.3.7 Rate of growth The rate of growth, which may be negative, is calculated according to the following process:

• the historical block loads, load transfers, and small-scale solar generation are adjusted out of the historical weather corrected loads to reveal the underlying trend; • the weather corrected and adjusted trends are reviewed by an expert panel to consider factors that could influence the growth rates, such as Local Government Plans; and • a growth rate of zero is applied to dedicated customer loads (connected at the subtransmission level). 3.2.3.8 Block loads and transfers Block loads for customer connections greater than a predefined threshold (as described below) are included after the application of underlying growth rates which specifically exclude these often large and lumpy changes in customer demand. A block load or transfer can result in either an increase or decrease in the forecast load (e.g. load can be transferred to or from a zone substation). This approach to block loads has been adopted as there is a need to distinguish between natural load growth and growth arising from these larger customer connections. Large individual customer connections at a spatial level is often sporadic in nature and including such loads in the trend can lead to an over or under forecast of demand for the network asset. Removing these changes in demand for the calculation of the trend ensure that we capture the underlying trend. Depending on the nature of block loads activity, some block loads may be individually small or there may be numerous block spot loads occurring around the same time at a given substation. To account for these possibilities, the sum of block loads for each year for each zone substation is compared to a threshold of 50A (approximately 1MVA @ 11kV). Where the sum is less than the threshold, the growth is considered to be organic and not included as a block load adjustment in the forecast. Block loads are differentiated to account for the differing nature of these customer connections. The block load categories are late stage 11kV block loads, early stage 11kV block loads and major customer connection block loads. Scaling factors are derived from a detailed analysis of actual historical customer demand and connection data which are then applied to the requested capacity.

A summary of the block load categories is as follows: Category Description Scaling Factor Early-stage General 11kV connections which have applied for 0.36 11kV connection Late-stage General 11kV connections which have received 0.58 11kV connection design approval Major 33kV+ connections or unique industry 11kV connections based on Customers (e.g. rail) industry

The higher resultant scaling factor for late stage 11kV block loads has been determined from detailed analysis of historical block load data and reflects the higher probability for a connection proceeding when a connection has progressed to this stage. As the 11kV scaling factors are derived from actual customer connection data and the actual resultant demand at the local 11kV panel and at the time of 11kV panel peak for real customer connections, they incorporate coincidence with peak, probability of proceeding and any industry-specific scaling factors in the case of major customer connections. Major customer connections have a representative scaling factor applied that varies depending on the industry type and expected customer future demand profile. Where available, actual demand data from existing customers by industry type is used to derive coincidence factors. A further probabilistic factor is applied to reflect the probability of occurrence and oversizing to derive an overall scaling factor for each individual major customer connection. An adjustment offsetting block load activity was implemented in the first 2 years of the 2020 forecast to account for the expected reduced construction activity and delays to 11kV customer connections arising from economic impacts from health measures in response to the COVID-19 pandemic. This offset comprised an impact accounting for both reduced population growth due to border restrictions and a general reduction in construction activity due to prevailing economic conditions. The Block Load COVID-19 adjustment was allocated spatially based on the existing forecasted 11kV block load connection activity. 3.2.4 Explanation of substation forecast outcomes Whilst 2020 actual demand was broadly in line with the 2019 forecast and historical trends indicate continuing growth trends, the resultant 2020 spatial maximum demand forecast at a system level is different to the 2019 forecast due to the onset of the COVID-19 pandemic and forecasted impacts due to the implementation of health

measures by governments. However, significant block load activity is continuing to drive higher growth rates at selected locations in the Sydney region. The 2020 forecast update includes continued improvements to forecast components including revision to the latest available relevant data sources, particularly in the econometric model. Forecast improvements in the area of energy efficiency, DER forecast modelling and spatial demand impacts of forecast electric vehicle uptake result in the net impact of these updated forecast components lowering forecast demand. Announcements of the extension and expansion to existing energy saving schemes and formulation of new schemes by the NSW government associated with the NSW Net Zero 2050 plan has increased the long-term impact of energy efficiency in the 2020 forecast. A DER forecast model rebuild has slightly increased long term impacts of rooftop solar and battery storage whilst better forecasting near term take up by blending model results with historical uptake trend. Electric vehicles are expected to provide a modest lift to demand beyond 2030 though pockets of network stress due to peak demand impact of electric vehicle uptake may exist spatially prior to 2030. The overall volume of large customer connection (block load) activity continues to be at the high levels seen in the 2019 forecast and this has a significant impact on the forecast at a local spatial level. In combination with a very high level of high-density residential developments, significant investment in road, rail and air transport infrastructure and rapid growth in data centre developments, large customer and generator connection activity remains at a rate not seen in over a decade. A forecast demand adjustment accounting for lower population increase and construction delays offsets some of the high-density residential development customer connection activity. Additional demand reduction from COVID impacts come from a sharp decline in forecasted income as economic conditions deteriorate in the near term. Economic recovery slowly progresses from year 3 onwards. In aggregate, the downward demand drivers in the 2020 forecast now have a greater long-term impact on forecasted demand when compared to 2019 and largely offset growth components such as future block load connections and economic growth. For the 2020 forecast, at the spatial level, around 26% of zones in summer and 40% of zones in winter are expected to experience growth in maximum demand over the next 5 years to 2025 (based on compound annual growth). This is down from 60% of zones in summer and steady at 40% of zones in winter expected to experience growth to 2025 in the 2019 forecast. 3.3 Transmission - distribution connection point load forecasts Ausgrid prepares an annual transmission distribution connection point forecast which is provided to TransGrid in May each year as part of the annual planning review and load forecast information provisions of the NER. A forecast of future loads over a ten year forward planning period is prepared for each dual function subtransmission substation connected to the TransGrid transmission network. These load forecasts are presented in Section 6.2.1 Dual function substation demand forecasts. As part of the annual load forecast development Ausgrid provides TransGrid with the “132kV TransGrid Report” which provides an input for their power system load flow modelling of the Ausgrid network. It contains MW, MVAr and uncompensated power factor data per year for the most recent actual year and 10 forecast years for each: • 132kV connection point (subtransmission substations, 132/11kV zone substations and 132kV customers); and • Zone substation supplied from other Distribution Network Service Providers (DNSPs), such as Epping, Leightonfield, and Hunters Hill, irrespective of supply voltage. 3.4 Subtransmission feeder load forecasts Ausgrid undertakes an annual review of subtransmission feeder capacity constraints (“the feeder load forecast”) using load-flow analysis to simulate credible network contingencies. Initial analysis is conducted using network load-flow models for a forward looking 20 year period, based on: • A 50% POE Planning Spatial Demand Forecast, including committed spot loads and uncommitted spot loads by applying a probability; • Committed network developments and load transfers, and • Line and cable cyclic normal and long-term emergency ratings. The results of this analysis form an input into the Area Planning process and the Annual Capital Review process. During these processes, a cost benefit analysis based on a probabilistic criteria is undertaken in order to maximise the economic benefit of investment to relieve identified constraints.

3.5 Primary distribution feeder load forecasts Ausgrid’s primary distribution feeder forecast contains peak load values that are selected seasonally and adjusted to account for temperature variation and abnormal switching on the distribution network. The summer and winter peak loads are identified by comparing the 15 minute interval load data for the primary distribution feeders to the associated zone substation historic peak load data. Any inconsistencies between the primary distribution feeder and zone substation interval data, as well as any abnormal load switching are identified. If there is no evidence of abnormal switching the primary distribution feeder peak load value can be assessed as normal and no further analysis of the historic load is required. If there is any evidence of abnormal switching, it is investigated and the load value is adjusted accordingly to compensate. The weather correction applied to the associated zone substation load is also applied to the primary distribution feeder if appropriate. The associated zone substation forecast load rate of growth (ROG) and known network changes (spot loads and transfers) are applied to the previously adjusted load value for a forward planning period covering the next 6 years if appropriate. There are no primary distribution feeders that exceeded their rating in the past year or are forecast to exceed it in the next two years during normal conditions. 3.5.1 Load transfer capacities of zone substations Load transfer capacity is the amount of load that can be restored in the event of a whole zone outage by switching the distribution network. The transfer capacities presented in the distribution demand forecast table as described in Section 3.1 assume that a single zone is rendered out of service and the rest of the network is in system normal configuration. Load transfers are generally considered to be a temporary solution as transferring load to neighbouring zone substations will increase the utilisation of the destination zone and feeders. This has an adverse impact on the operability of the network as the remaining distribution network is more highly utilised than planned and further restoration of subsequent contingencies may not be possible. Transfer capacities presented in this document are based on the configuration of the HV network in Summer 2019/20. Installation of additional HV interconnection and transfer capacity is typically a further consideration where it might provide a cost effective alternative to other capital investment associated with zone substations or the subtransmission network. Load transfer impacts are assessed on a case by case basis (typically in a load flow program) to ensure that the overall impact of load transfers does not overload assets in the distribution network. Additionally, a load transfer alters the configuration of the distribution network which may impact the capacity of subsequence load transfers. Therefore, the presented transfer capacities assume that no other load transfers have occurred. 3.6 Other factors having a material impact on the network 3.6.1 Fault levels TransGrid installed 50kA rated switchgear at Beaconsfield bulk supply point (BSP) during its condition driven replacement given that in some operating arrangements fault levels exceeded 40kA. Ausgrid is now installing equipment with this same fault rating in all new developments in the area. Nearby existing substations with 40kA rated switchgear, under certain operating scenarios, operate very close to their limits and this restricts some network configurations. There are numerous open points on the 132kV meshed transmission system due to these fault level limitations. These open points create more complicated switching arrangements and limit network flexibility.

132kV series reactors have been installed by TransGrid at Rookwood Rd BSP in part to limit fault level contribution (along with power flow control). In addition to these reactors open points were created on the 132kV network to restrict fault levels to below equipment ratings. For a number of 132/33kV sub-transmission substations (STS) refurbishments changes have been made in the standard arrangement for neutral earthing due to the limitations uncovered in past Ausgrid network standards. This results in individual transformer neutral earthing reactors being installed in place of a common neutral earthing resistor. The HV Network Reinforcement program is designed to overcome fault level issues in the HV network. These issues can be for both high and low fault levels. Feeders that have high fault levels can result in damage to

equipment. Feeders with low fault levels may have protection that cannot see or discriminate between fault locations which leads to increased clearing times or excessive customers being interrupted. Typical solutions to these issues are to upgrade the feeder, modify the protection settings or alter the network configuration. 3.6.2 Voltage levels Network power flow is changing from a traditional one-way flow towards a two-way flow. A major contributor to this change is the significant increase in “behind the meter” solar generating plants connected to the Ausgrid distribution network. Solar generating plants can significantly impact network voltages at times of high solar output which. Managing voltages across our network involves a BSP to the LV customer approach. Voltage levels at BSP’s, STS’s and zones have local regulation schemes that are optimised to cater for the change in power flow, and where required localised low voltage network voltages are managed by traditional techniques such as load balancing and DC tap changes in conjunction with exploring new technology such as STATCOMs and community batteries. There are also specific network areas with voltage related considerations. The meshed inner-metropolitan network is supplied by two large radial 330kV cables with very high charging capacitance. The inner-metropolitan network is also comprised of a number of long 132kV cables with significant cable charging. This means capacitor banks are required during cable outages to replace this lost reactive support, however during low load conditions shunt reactors are required to reduce voltages. These cables also have series reactors with bypass capabilities for power flow and fault level control. Capacitor banks are located at Beaconsfield BSP, Peakhurst STS and Bunnerong STS and shunt reactors at Rookwood Rd BSP, Beaconsfield BSP and Haymarket to help manage the voltage on the 132kV meshed network.

Since the commissioning of Rookwood Rd BSP, in order to manage voltage levels in the northern Sydney area, one of the two 132kV shunt reactors at Mason Park is almost always in service with the other one switched in during times of low load. One of the reactors at Mason Park are is presently defective with repairs expected to be completed by early December. The radial network connected to Muswellbrook BSP is supplied from three 132kV overhead feeders and spans a significant distance to Singleton 132kV STS. Under system abnormal conditions of the 132kV subsystem and high network loading, network voltages can drop below 0.9pu at Singleton 132kV STS. Closing of the normally open 132kV interconnector to Newcastle BSP will assist in maintaining system voltages during these conditions. Voltage control to manage 11kV network voltages is done at zone substations using tap changing transformers and where necessary capacitor banks. 3.6.3 Other power system security requirements Ausgrid’s under frequency load shedding capabilities are assessed on a bi-annual basis to ensure compliance with NER requirements. Projects are created where compliance is no longer met due to network topology rearrangements or at the request of AEMO. 3.6.4 Quality of supply Ausgrid endeavours to provide quality of supply to customers that is necessary to operate their equipment. In general, this is achieved by operating Ausgrid’s network, and requiring customers to operate their electrical installations, consistent with power quality requirements set out in the National Electricity Rules (NER), NSW Service and Installation Rules (SIR) and Ausgrid’s Network Standard NS238. Ausgrid investigates supply quality issues as they arise, including supply voltage, harmonics, and flicker. At Ausgrid, supply quality is monitored through permanent monitors at a selection of sites across the network at different voltage levels. Temporary supply quality monitors are installed at customer premises to investigate specific supply quality issues and complaints. 3.6.5 Embedded generation Ausgrid has published on its website, guidance for proponents seeking to connect an embedded generating system under Chapter 5A or Chapter 5 of the NER. The information includes guidelines, Network Standards, Electrical Standards and proforma contracts, and Connection Application forms. A register of completed generator connections is also maintained in accordance with the NER requirements. Ausgrid provides basic connection offers services and offers for inverter coupled micro embedded generator units up to 30kW where augmentation of the network is not required. Ausgrid is working with the AER to move this threshold up to 200kW for basic micro embedded generation connection offers services. All other embedded generating units are offered a negotiated template connection offer consistent with Chapter 5A for units that are not registered with AEMO and Chapter 5 in the case of Registered Generators of the Rules.

During 2019/2020, AEMO’s Distributed Energy Resources Register went live to which Ausgrid in collaboration with all Distribution Network Service Providers (DNSPs) nationally assisted AEMO in development/delivery of the register. The data gathered from all DNSP’s in AEMO’s DER register aims to increase the visibility of these types of systems across all electricity networks to support a consistent approach of reporting that will enable DNSP’s and AEMO to plan, forecast and manage the grid across the National Electricity Market (NEM) more efficiently. The DER Register has been in place from 1 December 2019 containing historical data and DNSPs have been working with AEMO to provide ongoing information from this date. For Ausgrid, the installer collaborative approach for updating the DER Register with installed equipment information will become effective from 18 May 2020. From this date, Ausgrid customers approved to install a new generating system or altering an existing generating system will be providing details of and verifying the installed DER equipment directly to the DER Register via the AEMO Installer Portal or a smart device application. This collaborative approach between Ausgrid, our customers and DER installers will assist Ausgrid improving data quality and to better understand the impact of DER across our network. Ausgrid continues to work with industry partners including the Clean Energy Council, ENA and other DNSP's & AEMO to better understand the current and future network impacts of embedded generation and the emerging battery storage market and its implications within Chapter 5A of the Rules. This includes working with the ENA and other DNSP to establish national guidelines for connection of embedded generation to facilitate the fair and efficient integration of distributed energy resources into the grid. National guidelines for basic micro, low voltage embedded generation connections were published during 2019 and are available from the ENA website here: https://www.energynetworks.com.au/projects/national-grid- connection-guidelines/ Work is underway to produce the next set of guidelines to address medium voltage (MV) and high voltage (HV) connections within the distribution system. Ausgrid has experienced a substantial increase in the number of customers applying to connect embedded generation, and particularly the level of activity in relation to Registered Participants and the interaction between the Ausgrid network and their respective generator proposals. This includes modification to existing embedded generators, new generator proposals and interactions with market aggregators. 3.7 Additional notes 3.7.1 Integrated System Plan AEMO publishes an Integrated System Plan annully under the functions of National Electricity Rules to maintain and improve system security of National Electricity (NEM) transmission grid. It provides an actionalble roadmap for eastern Australia’s power system to optimise consumer benefits and provides an overview of the current state and potential future development of the NEM transmission grid. The ISP includes a review of the: • Optimal development path needed for Australia’s energy system • Identification of forecast constraints on the national transmission flow paths • Whole-of-system plan to maximise net market benefits, and • Least-regret future scenario modelling and detailed engineering analysis. A copy of the annual ISP is available on AEMO’s website at https://www.aemo.com.au

3.7.1.1 NSW responsibility In the ISP, network augmentation proposals by TNSPs that affect national transmission flow paths are taken into account by AEMO in the development of conceptual augmentation options and market development scenarios. TransGrid is the Jurisdictional Planning Body (JPB) for NSW in the NEM. In this role TransGrid: • represents the NSW jurisdiction on the Inter-Regional Planning Committee (IRPC); and • provides jurisdictional information to the IRPC to enable it to assist AEMO in producing its annual Statement of Opportunities (SOO) and the ISP.

Accordingly, TransGrid is responsible for providing information concerning transmission developments in NSW which may affect the power transfer capacity of national transmission flow paths. Further details are available on TransGrid’s website at https://www.transgrid.com.au

4 Network Asset Retirements and Deratings

To maintain reliable, safe, sustainable and efficient network services to consumers Ausgrid manages the replacement of aged assets through a combination of individual projects and programs of work. These works manage the risks associated with asset failure, obsolescence (economic or technological), environmental as well as employee & Public Safety concerns. A major project is a discrete, non-recurring scope of work that has specific objectives, budget and resourcing. Due to their complexity and scale, major projects are planned at an area level to identify opportunities to efficiently address other replacement, augmentation or connection issues. Replacement programs consist of proactive and reactive programs. Proactive programs involve the planned replacement of assets where it has been determined that the supply or other risks of failure exceed the cost of replacement. Reactive programs are developed to replace assets where it is feasible to replace them at end of life or after failure. Due to the uncertain nature of reactive programs, no details of these replacements are provided in this report. The assets that Ausgrid is planning to replace as major projects and proactive replacement programs in the next five planning years are detailed in data tables published online, with the online data as described in Section 3.1. Assets with individual replacement values of less than $200,000 are grouped by asset category. In keeping with advice from the AER, that data is made accessible in a format that can been readily interrogated, forecast and related data tables are published online and can be accessed via the following web address: www.ausgrid.com.au/DTAPR 4.1 Feeder S20 and S21 De-rating Feeders S20 and S21 are predominantly OH feeders from Sydney STS which supply Warriewood SS and Narrabeen ZS. Warriewood Switching Station also supplies Mona Vale ZS, Carrel ZS and Newport ZS. The total length of Feeder S20 and S21 is approximately 21km and 16km respectively, with each feeder having short UG sections (up to 2km in total) to connect to Sydney East STS and Warriewood SS.

A program has commenced to assess OH subtransmission feeders and confirm they can be operated safely at their Maximum Operating Temperature (MOT), which subsequently determines the capacity of the feeder. This involves reviewing LIDAR data of feeders and identifying ground and conductor clearances which do not meet the requirements specified by AS7000 that defines the clearances of electrical conductors to eliminate the risk of electrocution caused by people and objects (e.g. vehicles on roads, vegetation) coming into close proximity of energised OH electrical conductors.

The assessment of Feeder S20 and S21 has identified approximately 20-30 locations on each feeder with design and construction issues. De-rating the feeders will reduce the risk of exposing the public to electrocution hazards by maintaining safe ground clearances. These 33kV feeders are predominantly OH construction utilising single timber structures and traverse bushland, residential areas and roads. The safety issue is primarily during the summer period where electrical conductors will sag more (due to increased ambient temperatures) and when demand on the network increases during hot days (generally above 35 °C). The de-rating of feeders S20 and S21 has commenced from November 2020.

5 Distribution Load Areas

This section should be read in conjunction with the rating and demand forecast data files which are available for download from Ausgrid’s website at www.ausgrid.com.au/DTAPR and as outlined in Section 3.1. DNSPs are required to provide information on anticipated system limitations in this Annual Planning Report (refer NER Schedule 5.8, clause (c)). Under the former licence conditions and planning standards, system limitations could be readily identified as constraints, due to the nature of the deterministic approach. However, with the removal of those standards, Ausgrid has adopted a probabilistic planning methodology, based on the AER suggested approach of assessing risk of expected unserved energy (EUE) against the value of customer reliability (VCR). In relation to the timing of anticipated system limitations, for the purpose of this Annual Planning Report, the proposed investment date is reported as determined by the cost / benefit analysis as part of the probabilistic planning methodology. Where appropriate, the date has been adjusted to allow for resourcing considerations. Only projects within a 5-year planning horizon are shown below. Consideration of remedial action is required when network elements exceed secure capacity. Identified limitations and indicative solutions are listed in Area Plan regional groupings, with the following information: • Substation – the name of the location, usually a zone or subtransmission substation; • Feeder – the name of the feeder, indicating the location of the feeder; • Timing – the identified need date by which a solution is planned to be implemented; and • System limitation – an identified network need. “Capacity” indicates there is a projected network capacity shortfall on the basis of expected unserved energy, and cost benefit analysis has been applied to identify an optimum solution and its timing. “Asset condition” refers to an asset being identified as having condition issues or approaching the end of service life, and cost benefit analysis has been applied to identify an optimum solution and its timing.

5.1 Camperdown and Blackwattle Bay load area 5.1.1 Description of Camperdown and Blackwattle Bay load area The Camperdown and Blackwattle Bay network area is a predominantly urban area on the fringe of the Sydney CBD. It includes high-density residential developments and commercial areas such as Darling Harbour, Broadway, Pyrmont and Camperdown. A small geographical area is supplied by Darling Harbour 132/11kV Zone Substation, Camperdown 33/11kV and Blackwattle Bay 33/5kV zone substations. There is one remaining Zone Substation in Ausgrid’s network that supplies electricity at 5kV, and conversion to 11kV is in progress. Camperdown ZS, Blackwattle Bay ZS and Darling Harbour ZS supply the suburbs of Pyrmont, Ultimo, Glebe, Camperdown, Forest Lodge and Annandale. Camperdown ZS also partly supplies the University of Sydney. Pyrmont STS is also included in the Camperdown and Blackwattle Bay network area. Supply at 33kV is provided from Pyrmont STS to three major customers: Barangaroo South, Sydney Trains and Global Switch (a data centre). The network in the Camperdown and Blackwattle Bay area has the following characteristics: • Darling Harbour ZS and Pyrmont STS are located in the same building and are both supplied at 132kV from Haymarket Bulk Supply Point (BSP); and • Camperdown 33/11kV ZS and Blackwattle Bay 33/5kV ZS are supplied from Pyrmont STS. Blackwattle Bay is the only zone with a 5KV distribution network in Ausgrid and hence, has very limited load transfer capability with adjacent zones. The 5kV distribution system in the Blackwattle Bay area is among the oldest assets in Ausgrid’s system. Ausgrid’s policy is to progressively replace the 5kV system with 11kV assets to increase operational flexibility by allowing load transfers between adjacent zone substations if required. There is a committed project to decommission Blackwattle Bay ZS by converting the 5kV to an 11kV system and transferring the load to Camperdown and Darling Harbour ZS. Details of this project are provided in Chapter 7.

Figure 5.1: Camperdown load area

5.1.2 Identified system limitations

Substation/ System limitation Load Impact on Discussion of Potential Credible Solutions Feeder name reduction Transmission - for 1 year Distribution Timing Driver deferral Connection (MVA) Points Nil

5.1.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects Substation/Feeder Name System Limitation Reason for Change Timing Driver Nil

5.2 Canterbury Bankstown load area 5.2.1 Description of Canterbury Bankstown load area The Canterbury Bankstown network area extends from Leightonfield in the north-west, Revesby in the south, and east as far as Dulwich Hill. The area encompasses a broad spectrum of load types from low density residential through to large commercial and industrial customers. The area contains substantial industrial precincts at Chullora, Leightonfield, Milperra and Padstow. Due to the anticipated Sydney Metro – City & Southwest project, both commercial and residential developments are forecasted in the Canterbury and Bankstown surrounding areas extending from Dulwich Hill to Bankstown. The network in the Canterbury Bankstown area: • is supplied from Ausgrid’s Inner Metropolitan transmission system, except for Revesby and Milperra zone substations, which are supplied from TransGrid’s Sydney South Bulk Supply Point; • includes 132/33kV subtransmission substations at Bankstown and Canterbury which supply five 33/11kV zone substations and provide 33kV supply to Sydney Trains and the M5 motorway; • includes six zone 132/11kV substations at Greenacre Park, Bankstown, Potts Hill, Sefton, Revesby and Milperra; • includes Leightonfield, a “stand-alone” 33kV zone substation, which is supplied from Endeavour Energy’s network at Guildford subtransmission substation; • includes substantial lengths of 33kV gas-pressure cables, which are an obsolete technology; and • is traversed by transmission feeders 92C, 92X, 91X2, 91Y2, 910, and 911.

There are number of committed projects in this area to address the issues related to Enfield, Greenacre Park and Dulwich Hill zones and also fluid filled cable from Sydney South BSP to Revesby zone. Details of these project are provided in Chapter 7.

Figure 5.2: Canterbury Bankstown load area

5.2.2 Identified system limitations

Substation/ System limitation Load Impact on Discussion of Potential Credible Solutions Feeder name reduction Transmission Timing Driver for 1 year -Distribution deferral Connection (MVA) Points 1.Milperra ZS Sep-24 Asset condition 18 MVA4 None Credible solutions include: (11kV 1. Refurbish Milperra ZS; (new limitation) switchgear) 2. Retire Milperra via new zone substation; 3. Retire Milperra ZS via load transfer; or 4. Defer retirement of Milperra ZS via demand management.

Note that the assessment was based upon preliminary assumptions for project costs, unserved energy and other benefits with a more detailed assessment to be conducted as part of the Regulatory Investment Test.

5.2.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects Substation/Feeder Name System Limitation Reason for Change Timing Driver 1. Leightonfield ZS Sep-28 Asset Condition Deferred from 2023 due to updated failure parameters and decreased load forecast.

4 The viability of a 1-year deferral is assessed by Ausgrid for each individual need and is dependent upon numerous factors, including the asset load profile, duration of outage events, load transfer capability of the local network, the expected impact of DM on unserved energy, the cost of the proposed preferred supply solution, discount rate and expected cost of DM solutions. The figure shown is the maximum demand in the “Timing” year less the load transfer capability.

5.3 Carlingford load area 5.3.1 Description of Carlingford load area The Carlingford network area extends east from Endeavour Energy's Carlingford subtransmission substation to Epping and Macquarie Park, and as far south as Hunters Hill and Meadowbank. The area is bounded by the supply boundary with Endeavour Energy to the north-west, by the Lane Cove River Valley to the north, and the Parramatta River and Sydney Harbour to the south and east. The Macquarie Park area, running along the northern boundary of the Carlingford network area contains significant commercial load arising from but not limited to: • Macquarie University; • Macquarie Park commercial area; • Data Centres; • Epping Town Centre precinct; and • North Ryde Station precinct. Significant commercial developments are expected to continue in this area as a result of the proposed North West rail line. Between the commercial areas there is significant residential load with high density development in the Epping, Macquarie Park, Meadowbank and Ryde areas. The distribution network in the Carlingford load area is supplied by two electrically separate subtransmission systems - a 66kV network supplied from Endeavour Energy’s Carlingford subtransmission substation, and Ausgrid’s 132kV network interconnected to TransGrid’s Sydney North Bulk Supply Point, Lane Cove Switching Station and Mason Park Switching Station. The area adjoins Endeavour Energy so some of the new developments around Epping Town Centre can be supplied via Endeavour Energy.

Figure 5.3: Carlingford load area

5.3.2 Identified system limitations

Substation/ System limitation Load Impact on Discussion of Potential Credible Solutions Feeder name reduction Transmission for 1 year -Distribution Timing Driver deferral Connection (MVA) Points Nil

5.3.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects Substation/Feeder Name System Limitation Reason for Change Timing Driver Nil

5.4 Eastern Suburbs load area 5.4.1 Description of Eastern Suburbs load area The Eastern Suburbs load area includes Sydney’s eastern seaboard from South Head to La Perouse, and extends inland to Surry Hills in the north-west, and west as far as Marrickville. The area encompasses a broad spectrum of load types from medium-density residential through to large commercial and industrial customers. The area contains substantial industrial precincts at Botany, Mascot and Alexandria, as well as major customers such as Sydney’s major domestic and international airports, the Garden Island Naval base, the University of New South Wales and the Sydney Cricket Ground/Football Stadium. The NSW Department of Planning, Industry and Environment views Alexandria as a corridor for major commercial and industrial growth in the medium-term future. The network in the Eastern Suburbs area: • is supplied from the Inner Metropolitan transmission network, including Bunnerong North subtransmission substation, Alexandria subtransmission substation and TransGrid’s Beaconsfield West and Haymarket Bulk Supply Points; • includes 132/11kV and 33/11kV zone substations, as well as 132kV and 33kV gas, oil and HSL feeders; • supplies high voltage customers including Sydney Trains, Sydney Airport, AMCOR, a large data centre, WestConnex and a chemical plant directly at 33kV; and • includes assets which are in poor condition, particularly 132kV and 33kV cables and many zone substation 11kV busbars. In addition to existing loads in the area, several other large load applications, in particular data centres and Transport for NSW projects in the Alexandria area, have been submitted to Ausgrid and are under development and construction. Information from town planning cites Alexandria as an area for major future development. These developments provide an opportunity to efficiently replace existing end-of-life assets at the same time as providing additional capacity where required.

Figure 5.4: Eastern Suburbs load area

5.4.2 Identified system limitations

Substation/ System limitation Load Impact on Discussion of Potential Credible Solutions Feeder name reduction Transmission for 1 year -Distribution Timing Driver deferral Connection (MVA) Points

1. Mascot ZS Dec-24 Asset Condition 3 MVA5 None Credible solutions include: (11kV 1. Refurbish existing Mascot ZS; switchgear) 2. Retire Mascot via new 33/11kV ZS; 3. Retire Mascot via new Mascot East 132/11kV ZS. The possible solution is 2. Feeders 327, Dec-24 Asset Condition As per None transfer some load to adjacent zones initially 328, 332, 337, Mascot and for the 132kV supply loop into existing 341 & 360 – ZS. See feeder 9FF (ex 91M/3)); Bunnerong item 1 4. Retire Mascot ZS via load transfer; North STS to above. Mascot ZS 5. Retire Mascot ZS in stages via load transfer; 6. Retire Mascot ZS in stages via load transfer and new Mascot East 132/11kV ZS; or 7. Defer retirement of Mascot ZS via demand management. An assessment of non-network options concluded that it was probable that sufficient demand management measures could be feasibly implemented to make the project deferral technically and economically viable. Ausgrid published a Non-Network Options Report in 2019 and received several demand management proposals. Since then, a revised network solution has been proposed involving the partial removal of load from the existing Mascot ZS. The revised solution is undergoing feasibility assessment and may affect the feasibility of demand management at Mascot. Note that the assessment was based upon preliminary assumptions for project costs, unserved energy and other benefits with a more detailed assessment to be conducted as part of the Regulatory Investment Test.

5.4.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects Substation/Feeder Name System Limitation Reason for Change Timing Driver Sydney Airport ZS Jan-24 Asset condition There is now a committed project to reconfigure Sydney Airport ZS 33kV arrangement. Paddington 33kV feeders 380, Mar-29 Asset condition Deferred from 2022 due to updated failure 381 and 382 parameters and decreased load forecast.

5 The viability of a 1-year deferral is assessed by Ausgrid for each individual need and is dependent upon numerous factors, including the asset load profile, duration of outage events, load transfer capability of the local network, the expected impact of DM on unserved energy, the cost of the proposed preferred supply solution, discount rate and expected cost of DM solutions. The figure shown is the maximum demand in the “Timing” year less the load transfer capability.

Substation/Feeder Name System Limitation Reason for Change Timing Driver Surry Hills ZS 33kV feeders 376, Sep-33 Asset condition Deferred from 2024 due to updated failure 383, 384 and 385 parameters and decreased load forecast.

5.5 Greater Cessnock load area 5.5.1 Description of Greater Cessnock load area The Greater Cessnock network area extends in the north to Rothbury and Allandale and south to Laguna and Quorrobolong. The area also extends from Kurri in the east, to Mt View and Pokolbin State Forest in the west. The area is geographically bounded by the Sugarloaf Mountain range in the east as well as the Watagan Mountains and Wollemi National Park to the south. Predominantly rural, the main urban development lies between and around Kurri township and the City of Cessnock. Development activity is focussed around the Pokolbin and Rothbury vineyard district, with ongoing winemaking and tourism development, as well as residential developments such as the Vineyards Resort at Rothbury becoming more prevalent. The new Huntlee township near Rothbury to the north of the area has commenced and will continue to grow over the next 20 years. The network in the Greater Cessnock area: • predominantly comprises a 33kV network supply from the Kurri subtransmission substation (STS), which is itself supplied via 132kV feeders from TransGrid Newcastle BSP at Killingworth; • includes two 132/11kV zone substations, one located at Rothbury and the other at Kurri; • includes four 33/11kV zone substations; • includes one 33kV connected mining customer near Ellalong; • consists of approximately 100km of predominantly overhead 33kV feeder network; • is partially traversed by a number of 132kV overhead feeders between Killingworth and Kurri STS; and • is traversed by 132kV and 66kV feeders between Kurri subtransmission substation and Singleton STS.

Figure 5.5: Greater Cessnock load area

5.5.2 Identified system limitations

Substation/ System limitation Load Impact on Discussion of Potential Credible Solutions Feeder name reduction Transmission- for 1 year Distribution Timing Driver deferral Connection (MVA) Points

Nil

5.5.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects Substation/Feeder Name System Limitation Reason for Change Timing Driver Nil

5.6 Inner West load area 5.6.1 Description of Inner West load area The Inner West load area extends from Homebush Bay in the north, south-west to Rozelle and Leichhardt and west as far as Auburn. The area is divided by parts of the harbour and the Lane Cove River. Parramatta Road runs through the southern part of the area. The network in the Inner West area: • is supplied from TransGrid’s transmission system at Sydney North, and via Chullora subtransmission switching station from Beaconsfield and Sydney South Bulk Supply Points; • includes 132/33kV subtransmission substations at Homebush, Strathfield and Rozelle; • includes six 132/11kV zone substations at Burwood, Croydon, Drummoyne, Flemington, Homebush Bay and Leichhardt, supplied via Mason Park subtransmission switching station; • includes three 33/11kV zone substations at Auburn, Concord and Lidcombe, supplied via Homebush subtransmission substation; and • includes planned new Transport of NSW infrastructure projects that may add to load in the area. There is a committed project to supply Auburn and Lidcombe zone substations from Endeavour Energy owned camelia Transmission Substation. Details of these project are provided in Chapter 7.

Figure 5.6: Inner West load area

5.6.2 Identified system limitations

Substation/ System limitation Load Impact on Discussion of Potential Credible Solutions Feeder name reduction Transmission for 1 year -Distribution Timing Driver deferral Connection (MVA) Points 1. Concord Aug-23 Asset Condition 29.6 MVA6 None The Regulatory Investment Test for (11kV Distribution (RIT-D) was been initiated for this Switchgear) project in October 2020.

Credible solutions include: 1. Refurbish Concord ZS; 2. Retire Concord via new zone substation; 3. Construction of a new substation to replace the existing Concord zone substation; 4. Retire Concord ZS via load transfer; or 5. Defer refurbishment of Concord ZS via demand management.

An assessment of non-network options concluded that it is not considered probable that sufficient demand management measures could be feasibly implemented to achieve the required demand reduction to make the project deferral technically and economically viable. The Draft Project Assessment Report and Notice on Screening for Non-Network Options can be found on Ausgrid’s website at https://www.ausgrid.com.au/ritd under ‘Addressing reliability requirements in the Concord area’.

5.6.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects Substation/Feeder Name System Limitation Reason for Change Timing Driver Nil

6 The viability of a 1-year deferral is assessed by Ausgrid for each individual need and is dependent upon numerous factors, including the asset load profile, duration of outage events, load transfer capability of the local network, the expected impact of DM on unserved energy, the cost of the proposed preferred supply solution, discount rate and expected cost of DM solutions. The figure shown is the maximum demand in the “Timing” year less the load transfer capability.

5.7 Lower Central Coast load area 5.7.1 Description of Lower Central Coast load area The Lower Central Coast area includes all of the Gosford local government area and a portion of Wyong Shire. The area extends south from Tuggerah Bulk Supply Point (BSP) to Broken Bay/Brisbane Water. There is bushland to the west of the region, and water to the east and south. The coastal area of the Lower Central Coast is a popular holiday destination and is a dormitory suburb for Sydney. The area is currently a mix of rural, residential, commercial and industrial land use. The network in the Lower Central Coast area: • is normally supplied from TransGrid’s transmission system at Tuggerah and Vales Point Bulk Supply Points to the north via Ausgrid’s Central Coast 132kV transmission system. There is also a “normally closed” connection with Sydney East Bulk Supply Point to the south; • includes a mix of 132kV, 66kV and 33kV feeders and 132/11kV, 66/11kV and 33/11kV zone substations. 132kV supply to zone substations is a relatively recent supply development in the area. Historically, areas of high load density were supplied at 66kV; • supplies Sydney Trains at 66kV via the Ourimbah subtransmission substation; and • provides a 33kV supply at Mangrove Creek for water pumping.

Figure 5.7: Lower Central Coast load area

5.7.2 Identified system limitations

Substation/ System limitation Load Impact on Discussion of Potential Credible Solutions Feeder name reduction Transmission for 1 year -Distribution Timing Driver deferral Connection (MVA) Points

Nil

5.7.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects Substation/Feeder Name System Limitation Reason for Change Timing Driver Nil

5.8 Lower North Shore load area 5.8.1 Description of Lower North Shore load area The Lower North Shore load area extends from Chatswood and Castle Cove in the north to North Sydney in the south, and east to Mosman. The network in the Lower North Shore area: • is supplied from TransGrid’s transmission system at Sydney East via four 132kV feeders to Lindfield switching station; • includes Castle Cove, Crows Nest, Mosman, North Sydney and RNSH 132/11kV zone substations and Willoughby subtransmission substation, which are supplied at 132kV from Lindfield switching station; • includes 33/11kV zone substations at Chatswood and Gore Hill, which are supplied radially at 33kV from Willoughby subtransmission substation; • includes 132kV oil filled cables, which are an obsolete technology, the replacement or retirement is in progress; • supplies high rise commercial load in Chatswood and North Sydney; • predominantly serves residential and commercial load; • includes the 33kV supplies to four major customers, the Lane Cove Tunnel, Sydney Metro – North West, Sydney Trains and Gore Hill Technology Park; and • includes planned new Transport of NSW infrastructure projects and data centres that may add to load in the area.

Figure 5.8: Lower North Shore load area

5.8.2 Identified system limitations

Substation/ System limitation Load Impact on Discussion of Potential Credible Solutions Feeder name reduction Transmission for 1 year -Distribution Timing Driver deferral Connection (MVA) Points Nil

5.8.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects Substation/Feeder Name System Limitation Reason for Change Timing Driver 1.Willoughby STS Dec-25 Asset condition (33kV Deferred from 2024. Further review of options to switchgear) supply major customers in the area is required, given the increase in magnitude, timeframe and likelihood of prospective loads proposed.

5.9 Maitland load area 5.9.1 Description of Maitland load area The Maitland network area extends in the north from Luskintyre and Woodville and south to Heddon Greta and Black Hill. The area is traversed from west to east by the Hunter River. The associated flood plains create the northern and eastern boundary along with Hexham Wetlands to the south. The majority of existing urban development lies along the New England Highway and railway transport corridor which passes from east to west through the middle portion of the area. Major residential development is continuing to the east of Maitland and around Thornton, and also to the west, north of Aberglassyn. The surrounding suburbs and villages contain a mixture of urban and rural development, with increasing amounts of light to medium industry along the main transport corridor. Intensive agricultural activities are also prevalent along the Hunter River flood plain. The network in the Maitland area includes: • Kurri and Beresfield subtransmission substations (STS) which are supplied via 132kV feeders from TransGrid’s transmission system at Killingworth (Newcastle); • one 132/11kV zone substation located at Brandy Hill; • six 33/11kV zone substations, three supplied from the 33kV network from Kurri STS, and three supplied from the 33kV network from Beresfield STS; • two 33kV connected mining customers and a 33kV connection for Hunter Water supply at Tarro; • 33kV feeder interconnections to the Tomago and Waratah 33kV networks via Tarro zone substation; and • provides the backup 33kV supply to the Essential Energy network supplying Martin’s Creek and Gresford.

Figure 5.9: Maitland load area

5.9.2 Identified system limitations

Substation/ System limitation Load Impact on Discussion of Potential Credible Solutions Feeder name reduction Transmission for 1 year -Distribution Timing Driver deferral Connection (MVA) Points 1. Tarro 33/11kV Sep-2024 Asset Condition, 15.3 MVA7 none Credible solutions include: Zone 11kV switchgear 1. Install new 11kV switchgear; Substation 2. Retire Tarro via new zone substation at Beresfield; 3. Defer retirement of Tarro ZS via demand management.

In the 2019 DTAPR, the Probabilistic Planning Assessments had shown that the best net economic benefit of all credible solutions was the replacement of the 11kV Switchgear at Tarro 33/11kV Zone Substation. The assessment was based on the probability of equipment failure and resulting load at risk if any. A reassessment of the need and risks is scheduled for early 2021. As part of the reassessment of the need, non- network solutions will be considered.

5.9.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects Substation/Feeder Name System Limitation Reason for Change Timing Driver Nil

7 The viability of a 1-year deferral is assessed by Ausgrid for each individual need and is dependent upon numerous factors, including the asset load profile, duration of outage events, load transfer capability of the local network, the expected impact of DM on unserved energy, the cost of the proposed preferred supply solution, discount rate and expected cost of DM solutions. The figure shown is the maximum demand in the “Timing” year less the load transfer capability.

5.10 Manly Warringah load area 5.10.1 Manly Warringah load area The Manly Warringah area is bordered on three sides by Middle Harbour and the Tasman Sea. It is separated from the adjoining Terrey Hills and Pittwater area by Narrabeen Lakes and bushland. The network serves both urban residential and commercial areas, with major industrial demand in Brookvale and Dee Why West, and retail demand at Warringah Mall. The area is principally residential. There is substantial high density development along the beachfront forming the eastern boundary of the area whereas the rest of the area is characterised by detached dwellings. The Manly Warringah network supplies Manly and most of Warringah Shire, and: • is supplied at 33kV from Warringah subtransmission substation (STS), which is in turn supplied from TransGrid’s Sydney East Bulk Supply Point by four 132kV circuits; • includes eight 33/11kV zone substations and one 132/33/11kV zone substation; and • is supplied by a complex network of 33kV feeders, comprising both overhead lines, which generally cover inland areas, and underground cables, which generally cover coastal areas.

Figure 5.10: Manly Warringah load area

5.10.2 Identified system limitations

Substation/ System limitation Load Impact on Discussion of Potential Credible Solutions Feeder name reduction Transmission for 1 year -Distribution Timing Driver deferral Connection (MVA) Points Nil

5.10.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects Substation/Feeder Name System Limitation Reason for Change Timing Driver Nil

5.11 Newcastle Inner City load area 5.11.1 Newcastle Inner City load area The Newcastle Inner City network area lies on the eastern seaboard of Newcastle. It is bounded by the Hunter River to the north and Glenrock State recreation area to the south and extends west to New Lambton. The area includes the principal CBD precinct for Newcastle, comprising a mixture of commercial and high density residential load. The surrounding suburbs contain a mixture of residential, commercial and industrial areas. Newcastle Harbour and the Hunter River, which form the northern boundary of the Newcastle Inner City area include the Honeysuckle development precinct along the foreshore and also contain several larger industrial 11kV customers including Port Waratah coal loading facility and State Dockyards at Carrington. The network in the Newcastle Inner City area: • is predominantly supplied at 33kV from Merewether subtransmission substation (STS); • is traversed by two 132kV feeders (960 & 961) which supply Merewether STS from TransGrid’s transmission system at Killingworth and a 132kV oil-filled cable, (9N9) which provides an alternative 132kV supply to Merewether STS from Waratah STS; • comprises six zone substations of which four are currently supplied from the 33kV network originating from Merewether STS and two are supplied from the 132kV network; • consists of around 36km of 33kV underground cables and 15km of overhead 33kV feeders; and • includes an underground 11kV triplex network supplying the Newcastle CBD area.

Figure 5.11: Newcastle Inner City load area

5.11.2 Identified system limitations

Substation/ System limitation Load Impact on Discussion of Potential Credible Solutions Feeder name reduction Transmission for 1 year -Distribution Timing Driver deferral Connection (MVA) Points Nil

5.11.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects Substation/Feeder Name System Limitation Reason for Change Timing Driver Nil

5.12 Newcastle Ports load area 5.12.1 Description of Newcastle Ports load area The Newcastle Ports network area extends from Hexham and Kooragang Island in the north to Mayfield and Waratah in the south. It is bordered on the east by Newcastle Harbour and extends west to Jesmond, Shortland and Sandgate. The area contains significant heavy industrial development including coal transport and ship- loading facilities, steel manufacturing and processing and other port related activities. General urban residential and commercial development is also present around the Mayfield and Shortland areas. The University of Newcastle is located at Callaghan, which is adjacent to the now retired Shortland zone substation. The principal heavy industrial development is located on either side of the south-arm of the Hunter River at Mayfield North and on Kooragang Island. The former BHP-Billiton steel-works site is now largely unused and has been targeted for future development for port-based commercial and industrial activities. With the retirements of Carrington 33kV Zone Substation, Mayfield 33kV Zone Substation and Kooragang 33kV Switching Station the 33kV Subtransmission network in the Newcastle Ports area have been disconnected from the network. Only customer owned 33kV feeders to various heavy industrial customers remains as well as the Kooragang Island 33kV distribution network. The network in the Newcastle Ports area: • receives supply from TransGrid’s Bulk Supply Points at Newcastle BSP and Waratah West BSP. The 132kV network emanating from these substations supply both subtransmission (STS) and zone substations (ZS) within the area; • there are a number of 132kV feeders that interconnect with adjacent areas – Newcastle Western Corridor and Newcastle Inner City; and • there is also one major customer (Onesteel) that is supplied from the 132kV network. • there is also one major customer (Molycop, previously Comsteel) that is supplied from the 33kV network.

Figure 5.12: Newcastle Ports load area

5.12.2 Identified system limitations

Substation/ System limitation Load Impact on Discussion of Potential Credible Solutions Feeder name reduction Transmission- for 1 year Distribution Timing Driver deferral Connection (MVA) Points Nil

5.12.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects Substation/Feeder Name System Limitation Reason for Change Timing Driver Nil

5.13 Newcastle Western Corridor load area 5.13.1 Description of Newcastle Western Corridor load area The Newcastle Western Corridor network area is bounded by Hexham Wetlands to the north, and extends south to Boolaroo and Holmesville. It includes the suburbs of Wallsend and Cardiff to the east and extends west to the M1 Pacific Motorway and Mount Sugarloaf. The area includes a mixture of residential, light industrial and commercial development as well as several coal mining operations. It contains the principal urban expansion areas for Newcastle and Lake Macquarie. There is ongoing residential development, particularly around Maryland and Fletcher, as well as between Edgeworth and Cameron Park. The Glendale area is becoming an increasingly important commercial and transport hub as urban development in the area continues. The network in the Newcastle Western Corridor area: • is currently supplied from Argenton subtransmission substation; • consists of two older 33/11kV zone substations at Cardiff and Edgeworth; • includes two new 132/11kV zone substations at Maryland and Argenton; • contains two 33kV connected mining customers; • consists of approximately 40km of predominantly overhead 33kV feeder network; • contains TransGrid’s 330/132kV Newcastle Bulk Supply Point at Killingworth; and • is traversed by several 132kV overhead feeders between Killingworth Bulk Supply Point and a number of Ausgrid substations.

Figure 5.13: Newcastle Western Corridor load area

5.13.2 Identified system limitations

Substation/ System limitation Load Impact on Discussion of Potential Credible Solutions Feeder name reduction Transmission for 1 year -Distribution Timing Driver deferral Connection (MVA) Points

Nil

5.13.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects Substation/Feeder Name System Limitation Reason for Change Timing Driver Nil

5.14 North East Lake Macquarie load area 5.14.1 Description of North East Lake Macquarie load area The North East Lake Macquarie load area is bounded by Lake Macquarie to the west and the Pacific Ocean to the east. The load area extends from Charlestown in the north to Catherine Hill Bay in the south. The North East Lake Macquarie area includes the Charlestown CBD precinct, which comprises typical inner city commercial load. The surrounding suburbs contain a mixture of residential and commercial areas. The opportunity exists for significant future beachside and lakeside developments, particularly to the south of Swansea Channel. Increasing densities within both residential and commercial areas are anticipated for much of the area, particularly around Charlestown, which is becoming the principal commercial centre for Lake Macquarie. The network in the North East Lake Macquarie area: • is currently supplied from both Merewether subtransmission substation (STS) and Argenton STS which are both supplied via 132kV feeders from TransGrid’s transmission system at Killingworth; • consists of six 33/11kV zone substations, of which four are supplied from the 33kV network originating from Merewether STS, and two (Mt Hutton and Croudace Bay) are supplied from the 33kV network from Argenton STS; • consists of one 132/11kV zone substation at Charlestown; • is a predominantly overhead 33kV feeder network with a combined total length of more than 110 km; and • is traversed on its northern boundary by a double circuit 132kV tower line from Newcastle 330kV substation to Merewether STS.

Figure 5.14: North East Lake Macquarie load area

5.14.2 Identified system limitations

Substation/ System limitation Load Impact on Discussion of Potential Credible Solutions Feeder name reduction Transmission for 1 year -Distribution Timing Driver deferral Connection (MVA) Points Nil

5.14.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects Substation/Feeder Name System Limitation Reason for Change Timing Driver Nil

5.15 North West Sydney load area 5.15.1 Description of North West Sydney load area The North West network area includes the area from Sydney North Bulk Supply Point in the north, north-east to Berowra and south to Pennant Hills. The area is relatively geographically isolated, bordering Ku-ring-gai Chase National Park and other bush land. The main Sydney to Newcastle freeway and railway run through the eastern edge of this area. Most loads in this area arise from urban residential development in the south-eastern half of the area. Development is mixed and ranges from high-value residential properties in the Cherrybrook area to large scale apartment development at Hornsby. The network in the North West area: • is supplied from TransGrid’s transmission system at Sydney North Bulk Supply Point; • consists of three 132/11kV zone substations at Berowra, Hornsby, Pennant Hills supplied on a 132kV ring from Sydney North BSP, and Galston zone substation supplied from Sydney North BSP; and • includes a 66kV supply to Sydney Trains from Berowra zone substation.

Figure 5.15: North West Sydney load area

5.15.2 Identified system limitations

Substation/ System limitation Load Impact on Discussion of Potential Credible Solutions Feeder name reduction Transmission for 1 year -Distribution Timing Driver deferral Connection (MVA) Points Nil

5.15.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects Substation/Feeder Name System Limitation Reason for Change Timing Driver Nil

5.16 Pittwater and Terrey Hills load area 5.16.1 Description of Pittwater and Terrey Hills load area The Pittwater & Terrey Hills network area forms a long, narrow corridor beginning at Sydney East subtransmission substation (west of Belrose), and extending from Terrey Hills to Palm Beach in the north, and down the coast to Narrabeen. The area is bounded to the west by bushland and Broken Bay, and to the north and east by the Tasman Sea. The area is primarily low density residential, although there is continuing development of medium density housing in the Warriewood area. The network in the Pittwater & Terrey Hills area: • is supplied from TransGrid’s transmission system at the TransGrid/Ausgrid Sydney East subtransmission substation via two 120MVA transformers and three overhead 33kV feeders to Terrey Hills and Narrabeen zone substations, and Warriewood subtransmission switching station; • has two connection points with the Manly-Warringah distribution network to the south, which provides limited emergency back-up in the event of multiple 132/33kV transformer outages; and • has a 5MW landfill gas generator at Belrose which feeds in at Sydney East subtransmission substation 33kV busbar supplying the network.

Figure 5.16: Pittwater and Terrey Hills load area

5.16.2 Identified system limitations

Substation/ System limitation Load Impact on Discussion of Potential Credible Solutions Feeder name reduction Transmission for 1 year -Distribution Timing Driver deferral Connection (MVA) Points 1. Feeder S20 Sep-21 Capacity, 28.3 MVA8 None Credible solutions include: Sydney East Reliability 1. Rectify OH sections STS to 2. Build new 33kV feeder Warriewood SS 3. 11kV load transfer and Narrabeen 4. Demand management ZS Probabilistic Planning Assessments have (new limitation) shown the best net economic benefit of all credible solutions is the upgrade of OH sections of Feeder S20. The assessment is based on the probability of feeder faults and resulting load at risk if any. It is expected that the refurbishment of various OH sections of Feeder S20 will be completed in 2021. The capacity constraint is a result of both design and construction issues recently identified by assessing the LIDAR data of the feeder. An assessment of non-network options concluded that it was not considered probable that sufficient demand management measures could be feasibly implemented to achieve the required demand reduction to make the project deferral technically and economically viable. The required expenditure to rectify the OH sections that do not meet modern design standards does not require a Regulatory Investment Test. 2. Feeder Sep-21 Capacity, 34.7 MVA9 None Credible solutions include: S21 Sydney Reliability 1. Rectify OH sections East STS to 2. Build new 33kV feeder Warriewood SS 3. 11kV load transfer and Narrabeen 4. Demand management ZS Probabilistic Planning Assessments have (new limitation) shown the best net economic benefit of all credible solutions is the upgrade of OH sections of Feeder S21. The assessment is based on the probability of feeder faults and resulting load at risk if any. It is expected that the refurbishment of various OH sections of Feeder S20 will be completed in 2022. The capacity constraint is a result of both design and construction issues recently identified by assessing the LIDAR data of the feeder.

8 The viability of a 1-year deferral is assessed by Ausgrid for each individual need and is dependent upon numerous factors, including the asset load profile, duration of outage events, load transfer capability of the local network, the expected impact of DM on unserved energy, the cost of the proposed preferred supply solution, discount rate and expected cost of DM solutions. The figure shown is the maximum demand in the “Timing” year less the load transfer capability.

9 The viability of a 1-year deferral is assessed by Ausgrid for each individual need and is dependent upon numerous factors, including the asset load profile, duration of outage events, load transfer capability of the local network, the expected impact of DM on unserved energy, the cost of the proposed preferred supply solution, discount rate and expected cost of DM solutions. The figure shown is the maximum demand in the “Timing” year less the load transfer capability.

Substation/ System limitation Load Impact on Discussion of Potential Credible Solutions Feeder name reduction Transmission for 1 year -Distribution Timing Driver deferral Connection (MVA) Points An assessment of non-network options concluded that it was not considered probable that sufficient demand management measures could be feasibly implemented to achieve the required demand reduction to make the project deferral technically and economically viable. The required expenditure to rectify OH sections that do not meet modern design standards does not require a Regulatory Investment Test.

5.16.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects Substation/Feeder Name System Limitation Reason for Change Timing Driver Nil

5.17 Port Stephens load area 5.17.1 Description of Port Stephens load area The Port Stephens network area approximately coincides with Port Stephens local shire area. It extends from Nelson Bay and the coastline in the east, to Raymond Terrace in the west, and from Karuah in the north, to Stockton and Tomago in the south. The area is very diverse and includes tourism-based commercial development, heavy industrial development, the RAAF Fighter Base, and Newcastle Airport at Williamtown. The Port Stephens area has been targeted for future development and continues to grow steadily. Medium density tourist-related and residential urban development is prevalent around Nelson Bay. Two precincts have been identified at Medowie and Raymond Terrace for major subdivision developments. Tanilba Bay and Anna Bay have been earmarked for other large residential developments. The industrial developments at Heatherbrae and Tomago both have large portions of land subdivided for industrial development. The network in the Port Stephens area: • is supplied from Tomago subtransmission substation (STS); • includes eight zone substations all of which are supplied from the 33kV network from Tomago; • includes 33kV customer connections for the RAAF Fighter Base at Williamtown, Hunter Water Corporation at Tomago and AGL; • provides a back-up 33kV supply to Tea Gardens for Essential Energy; and • consists of approximately 195km of predominantly overhead 33kV feeder network.

Figure 5.17: Port Stephens load area

5.17.2 Identified system limitations

Substation/ System limitation Load Impact on Discussion of Potential Credible Solutions Feeder name reduction Transmission for 1 year -Distribution Timing Driver deferral Connection (MVA) Points Nil

5.17.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects Substation/Feeder Name System Limitation Reason for Change Timing Driver 1. Stockton 33/11kV Zone Sep-2021 Asset Condition Progressed to committed project Substation (11kV switchgear)

5.18 Singleton Load area 5.18.1 Description of Singleton load area The Singleton network area extends from Liddell in the west and Westbrook to the north, through to Branxton in the east and south to the Putty Valley. The area is very diverse and includes residential customers, light to heavy industry, coal mining, agriculture, a number of vineyards and wineries, as well as dairy and beef farms and several horse studs. There are a number of residential developments to the north of Singleton and there is also likely to be increasing industrial activity in the Whittingham area south-east of Singleton. The principal developed areas are clustered around the New England Highway and rail network, with the main township of Singleton centrally located. There are many smaller rural communities around Singleton, including Bulga, Branxton, Greta, Broke, Jerry’s Plains, Putty Valley, Belford, Elderslie, Mitchell’s Flat and Glendon Brook. The network in the Singleton area: • is supplied from the Singleton 132/66kV STS and the Liddell 33kV Switching Station at Liddell Power Station; • has an expansive 66kV subtransmission system comprising two closed ring networks; • includes a 66kV interconnection to Kurri STS via Branxton zone substation; • includes a smaller 33kV network supplied from AGL auxiliary 33kV supply at Liddell, which supplies a number of mining operations and conveyors; • includes seven 66/11kV zone substations and a number of Ausgrid-owned switching station sites on the Liddell 33kV network; and • has over twenty 66kV and 33kV connected mining customers.

The Singleton network area also contains AGL owned coal fired Power Stations, Bayswater and Liddell, forming part of NSW base load generation. AGL has formally indicated its intention to decommission Liddell Power Station in 2023. The expected closure of Liddell Power Station may require Ausgrid to seek alternate supply options for the 33kV network connected to the auxiliary supply from Liddell Power Station. Ausgrid is currently developing these supply options in consultation with AGL and TransGrid.

Figure 5.18: Singleton load area

5.18.2 Identified system limitations

Substation/ System limitation Load Impact on Discussion of Potential Credible Solutions Feeder name reduction Transmission for 1 year -Distribution Timing Driver deferral Connection (MVA) Points Nil

5.18.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects Substation/Feeder Name System Limitation Reason for Change Timing Driver Nil

5.19 St George load area 5.19.1 Description of St George load area The St George network area extends west from Arncliffe and Sans Souci on Botany Bay, and inland to Peakhurst. This is a predominantly urban area that includes high density residential developments and commercial areas such as the Hurstville retail district. Population growth continues to drive load growth along the rail corridor. The East Hills and Illawarra railway lines and Princes Highway pass through the area. There are limited opportunities for connection with other areas of the network because of various geographic, network and physical features of the area, including water, transport infrastructure and customer load control frequencies. The network in the St George area: • is supplied from Peakhurst subtransmission substation via two 132kV feeders from TransGrid’s transmission system at Sydney South Bulk Supply Point; • Includes four 33/11kV zone substations Blakehurst, Mortdale, Riverwood and Sans Souci; • three 132/11kV zone substations Hurstville North, Kogarah and Rockdale; and • is traversed by 132kV XLPE cables from Peakhurst to Canterbury and Beaconsfield BSP.

Figure 5.19: St George load area

5.19.2 Identified system limitations

Substation/ System limitation Load Impact on Discussion of Potential Credible Solutions Feeder name reduction Transmission for 1 year -Distribution Timing Driver deferral Connection (MVA) Points Nil

5.19.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects Substation/Feeder Name System Limitation Reason for Change Timing Driver 1.Riverwood ZS Sep-28 Asset condition (11kV Deferred from 2023 due to decreased load switchgear) forecast

5.20 Sutherland load area 5.20.1 Description of Sutherland load area The Sutherland network area extends from the Kurnell Peninsula in the north-east, along the southern side of Botany Bay and the Georges River, south as far as Waterfall and east towards the coast. It serves a mixture of residential, commercial and industrial areas. The network in the Sutherland area: • is supplied from TransGrid’s bulk supply point at Sydney South, via two double circuit 132kV tower lines • includes four 33/11kV zone substations supplied from 132/33kV subtransmission substations (STS) at Port Hacking together with five 132/11kV and one 132/33/11kV zone substations • consists mainly of overhead lines, operating at 132kV and 33kV; • is exposed to a marine atmosphere in some places due to its proximity to the ocean (especially feeders 916 and 917); • has connections at 33kV to two landfill gas generators at Lucas Heights; • supplies Sydney Trains at Heathcote and Port Hacking, ANSTO at Lucas Heights, Caltex oil refinery, Sydney Water Desalination Plant at Kurnell, and Sydney Water at Woronora Dam; and • includes the ability to provide a 132kV back up supply to Endeavour Energy at Bellambi in the south.

Figure 5.20: Sutherland load area

5.20.2 Identified system limitations

Substation/ System limitation Load Impact on Discussion of Potential Credible Solutions Feeder name reduction Transmission for 1 year -Distribution Timing Driver deferral Connection (MVA) Points Nil

5.20.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects Substation/Feeder Name System Limitation Reason for Change Timing Driver Nil

5.21 Sydney CBD Load Area 5.21.1 Description of Sydney CBD load area The Sydney CBD network area extends from Circular Quay in the north, west to Darling Harbour, east to Woolloomooloo, and south to Haymarket. Bounded by Darling Harbour, Central Railway Station and the Domain, it comprises an area of less than 3 square kilometres. This is the commercial heart of Sydney, which contains approximately 45% of Sydney’s office space and is home to some 49,000 residents. The network in the Sydney CBD area: • includes 132/11kV zone substations at City Central, City North, City South and Dalley St. and a 33/11kV zone substation at City East; • is supplied at 132kV from TransGrid’s Haymarket Bulk Supply Point and from Ausgrid’s Inner Metropolitan Transmission network which includes supply from Rozelle and Lane Cove STSS; • includes 33kV supply to City East 33/11kV zone substation sourced from Surry Hills STS; • is an underground network, and • at the 11kV level, is predominantly of an underground triplex10 construction and provides an N-1 distribution supply. There is a committed project to retire City East 33/11kV zone substation by transferring all load to Belmore Park zone substation. Details of this project are provided in Chapter 7.

Figure 5.21: Sydney CBD load area

10 The triplex design used on much of the distribution network in the CBD means distribution substations generally comprise three distribution transformers supplied radially by three 11kV feeders.

5.21.2 Identified system limitations

Substation/ System limitation Load Impact on Discussion of Potential Credible Solutions Feeder name reduction Transmission for 1 year -Distribution Timing Driver deferral Connection (MVA) Points

1. Dalley St ZS Dec-23 Asset Condition 21.0 None The Regulatory Investment Test for (11kV MVA11 Distribution (RIT-D) was completed for this Switchgear) project in November 2018 along with City East decommissioning project and is part of the preferred staged strategy for the Sydney 2. Feeders Dec-23 Asset Condition CBD area. 92M/2, 928/1, (oil filled) 92L/1 and The project assessment report considered 929/2 two credible network options and non-network alternatives; determining that the option with the highest net market benefits was for the transfer of the substation loads of City East and Dalley Street zone substations to the Belmore Park zone substation in one 2×10 way duct bank and decommissioning City East and Dalley Street zone substations and its associated feeders. Following retirement of Dalley St ZS the 132kV feeders 92M/2, 928/1, 92L/1 and 929/2 are no longer required and will be decommissioned. The draft and final project assessment reports and notice of non-network options can be found on Ausgrid’s website at www.ausgrid.com.au/ritd under ‘Addressing reliability requirements in the Sydney CBD’.

5.21.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects Substation/Feeder Name System Limitation Reason for Change Timing Driver Nil

11 The viability of a 1-year deferral is assessed by Ausgrid for each individual need and is dependent upon numerous factors, including the asset load profile, duration of outage events, load transfer capability of the local network, the expected impact of DM on unserved energy, the cost of the proposed preferred supply solution, discount rate and expected cost of DM solutions. The figure shown is the maximum demand in the “Timing” year less the load transfer capability.

5.22 Upper Central Coast load area 5.22.1 Description of Upper Central Coast load area The Upper Central Coast area covers the Wyong Shire and includes the area north of Tuggerah Bulk Supply Point , extending to Vales Point in the north, east to the coast, and to the western boundary of Wyong shire. The area includes Tuggerah Lakes and Lake Munmorah, which largely separate the inland areas from major industries include coal mining and power generation. The network in the Upper Central Coast area is comprised of a southern 132kV system and a northern 33kV system. The 132kV southern system: • comprises of a 132kV line linking TransGrid’s 330/132kV Munmorah and Tuggerah bulk supply points; • consists of three 132/11kV zone substations at Wyong, Charmhaven and Lake Munmorah; • provides support to TransGrid’s Tuggerah 330/132kV substation which is currently supplied by two 330kV feeders and transformers; and • includes a 132kV line running from Vales Point to Morisset zone substation (West Lake Macquarie area) and Ourimbah subtransmission substation. Although this line traverses the area, it does not supply the load within the area. The 33kV northern system: • comprises two radial feeders which are supplied from Munmorah STS, supplying zone substations at Noraville and Vales Point.

Figure 5.22: Upper Central Coast load area

5.22.2 Identified system limitations

Substation/ System limitation Load Impact on Discussion of Potential Credible Solutions Feeder name reduction Transmission for 1 year -Distribution Timing Driver deferral Connection (MVA) Points

Nil

5.22.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects Substation/Feeder Name System Limitation Reason for Change Timing Driver Nil

5.23 Upper Hunter load area 5.23.1 Description of Upper Hunter load area The Upper Hunter area is a large area extending to Wingen in the north, Liddell to the south-east and Kars Springs to the north-west. The main townships in the area are Muswellbrook, Aberdeen, Scone, Denman and Merriwa. Around these towns are many smaller rural communities including Moonan, Rouchel, Ellerston, Wingen, Parkville, Glenbawn, Dartbrook, Baerami and Sandy Hollow. Most of the area is either rural or sparsely developed and includes many isolated and remote dwellings. Other than some residential developments occurring around Muswellbrook and on the eastern side of Scone, there is limited urban expansion taking place in the area. The area includes urban residential, light to heavy industrial development - particularly coal mining, as well as extensive vineyards, wineries, dairy and beef industries and horse studs. Predominant economic activities are power generation and coal mining. Future connection of generation in this area is considered to be possible but has significant uncertainty. The network in the Upper Hunter area: • is supplied from both Mitchell Line 132/66kV subtransmission substation (STS) and Muswellbrook 132/33kV STS which are supplied via 132kV feeders from TransGrid’s transmission system at Sandy Creek near Muswellbrook; • includes nine Ausgrid zone substations, with four supplied at 66kV and the rest at 33kV; • includes six mining customers; with one supplied at 33kV and the others at 66kV; • includes a 33kV connection point for the Glenbawn Hydro-generator near Rouchel; • includes more than 200km of overhead 33kV & 66kV feeder network; and • consists of a predominantly radial subtransmission system with either limited or non-existent 11kV interconnections.

Figure 5.23: Upper Hunter load area

5.23.2 Identified system limitations

Substation/ System limitation Load Impact on Discussion of Potential Credible Solutions Feeder name reduction Transmission for 1 year -Distribution Timing Driver deferral Connection (MVA) Points

Nil

5.23.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects Substation/Feeder Name System Limitation Reason for Change Timing Driver 1. Muswellbrook 132/33kV Aug- Asset Condition Project is now committed Subtransmission Substation 2022 (33kV switchgear) 2. Muswellbrook 33/11kV Zone Aug- Asset Condition Project is now committed Substation 2022 (33kV switchgear)

5.24 Upper North Shore load area 5.24.1 Description of Upper North Shore load area The Upper North Shore network area extends from St Ives in the north, west to Turramurra, through Pymble and south to Lindfield. The Pacific Highway and the North Shore and Western railway lines run through the area. The Upper North Shore is a predominantly urban area that includes residential and commercial load. The network in the Upper North Shore area: • is supplied via Kuring-gai subtransmission substation via a radial 33kV underground network. Kuring-gai STS is supplied from TransGrid’s transmission system at Sydney East Bulk Supply Point via two 132kV feeders, 9E1 and 9E2, which predominantly comprise a single double circuit tower line • consists of Pymble, Lindfield, St Ives and Turramurra zone substations supplied from Kuring-gai STS • provides standby supplies to Sydney Trains at 33kV from a busbar at Gordon, teed off a feeder from Kuring- gai STS to Lindfield zone substation, and • supplies both residential and commercial load.

Figure 5.24: Upper North Shore load area

5.24.2 Identified system limitations

Substation/ System limitation Load Impact on Discussion of Potential Credible Solutions Feeder name reduction Transmission for 1 year -Distribution Timing Driver deferral Connection (MVA) Points Nil

5.24.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects Substation/Feeder Name System Limitation Reason for Change Timing Driver Nil

5.25 West Lake Macquarie load area 5.25.1 Description of West Lake Macquarie load area The West Lake Macquarie network area lies along the western edge of Lake Macquarie, located south-west of Newcastle. The area extends from Teralba in the north to Wyee in the south, and west to Wakefield, Cooranbong and Mandalong. The area includes Toronto town centre and emerging Morisset regional centre, as well as a mix of urban residential and light industrial areas. Most of the existing urban development is concentrated in the vicinity of the Lake Macquarie shore-line. The surrounding areas contain a mix of industrial, power generation, coal-mining and semi-rural areas. The M1 Pacific Motorway and the main northern rail-line pass through the area. There is opportunity for continued urban development in the area as there are large tracts of vacant land. Cooranbong has been identified in the Department of Planning’s Lower Hunter regional strategy as a priority land release area, with 3,000 new lots expected to be released. The network in the West Lake Macquarie area: • is supplied from both Awaba STS and Eraring STS via 132kV feeders from TransGrid’s transmission system at Killingworth and Vales Point; • includes six zone substations. Three of the six zone substations are supplied from the 33kV network originating at Eraring STS (of which two are dedicated to mining customers). The remaining three zone substations are supplied from the 132kV network; • provides dedicated 11kV supply to underground coal-mining operations at Myuna and Cooranbong via two of the zone substations; • includes three 33kV-connected mining customers (Mandalong, Awaba and Newstan) and a 33kV connection for railway supplies at Awaba; • consists of approximately 105km of predominantly overhead 33kV feeder network; and • serves most of the area’s 11kV supply needs from Avondale ZS, Toronto West ZS, Rathmines ZS and Morisset ZS.

Figure 5.25: West Lake Macquarie load area

5.25.2 Identified system limitations

Substation/ System limitation Load Impact on Discussion of Potential Credible Solutions Feeder name reduction Transmission for 1 year -Distribution Timing Driver deferral Connection (MVA) Points

Nil

5.25.3 Identified Substation and Feeder limitations changes from last year’s DAPR - deferred or committed projects Substation/Feeder Name System Limitation Reason for Change Timing Driver Nil

5.26 Primary distribution feeder limitations There were no distribution feeder trunk section ratings exceeded in the preceding year, or expected to be exceeded over the next two years during normal conditions. Distribution feeders are proactively planned to not exceed their ratings by performing regular assessment of the existing feeder network and the proposed network within a 6-year horizon. Additionally, distribution feeders are assessed for new HV connections to ensure there is enough capacity and the new connection does not cause an overload. An augmentation project is initiated if a future overload is forecast to occur. A final assessment of every distribution feeder is performed prior to onset of summer to identify if any feeders will exceed their trunk section rating in its normal configuration. Any feeder expected to exceed its rating will, where possible, have action taken to address the constraint before the summer peak. This occurs because the resultant configuration of the distribution network has a reduced ability to restore supply in the event of a subsequent contingency compared to the planned ability.

6 Transmission Load Areas

6.1 Preliminary notes 6.1.1 Changes in dual function asset status The list of Ausgrid’s dual function assets is reviewed periodically and is used as input for preparing Ausgrid’s regulatory reporting, regulatory submission and pricing methodology. For the purpose of the regulatory submission, the list of dual function assets is determined based on the forecast load and the system configuration as at the beginning of the regulatory period. Ausgrid’s dual function network is defined as those assets with a voltage 66kV and above that are owned by Ausgrid and operate in parallel with and provide material support to the TransGrid transmission network. These assets may either operate in parallel with the transmission network during normal system conditions, or can be configured so that they operate in parallel during specific system conditions. An asset is deemed to provide material support to the TransGrid transmission network if: • there is otherwise limited or no system redundancy within TransGrid’s network, or • investment in the transmission system would be required within the regulatory period if that network asset did not exist, or • the feeder provides operational support to the transmission network (e.g. to facilitate maintenance of transmission assets or improve security of supply) and the asset provides an effective parallel with the transmission network via a relatively low impedance path. 6.1.2 Dual function connection points The NER requires a TNSP to set out planning proposals for dual function connection points. Ausgrid’s joint planning with customers, TransGrid and other NSPs may involve the establishment of new connection points. These augmentations are driven by constraints on the distribution network. However, when the augmentation options are considered in the future, the preferred solution may comprise a mix of dual function and distribution network augmentations. Planning of new or augmented connections involves consultation between Ausgrid and the connecting party, the determination of technical requirements, and the completion of connection agreements. New connections can result from joint planning with TransGrid, other DNSPs, or be initiated by generators or customers through the application to connect process. 6.1.3 Inter-Network Impact The Augmentation proposals described in this report are reliability projects and do not have a detrimental material inter-network impact.

6.2 Ausgrid System Total Maximum Demand Forecasts The forecast system total summer maximum demand and the system total winter maximum demand is shown below. Each chart displays the actual and weather corrected actual maximum demand to 2019/20 and the 50% Probability of Exceedance (PoE) forecast maximum demand from 2020/21 in megawatts (MW).

Figure 6.1: Summer Global Peak Forecast

Figure 6.2: Winter Global Peak Forecast

6.2.1 Dual function substation demand forecasts Actual and forecast demand data tables (summer and winter) for individual dual function substations are published online and can be accessed on Ausgrid’s website at www.ausgrid.com.au/DTAPR . 6.3 Transmission load area - Central Coast 6.3.1 Description of Central Coast transmission load area Ausgrid prepares a Central Coast Transmission Load Area plan that covers all Ausgrid 132kV subtransmission assets and dual function assets which operate in parallel and support the main TransGrid transmission network in the Lower Central Coast and Upper Central Coast subtransmission load areas. It forms the basis for TransGrid – Ausgrid joint planning and the sharing of network models and data in the Central Coast area. The Central Coast transmission load area includes all of the Gosford and Wyong local government areas. The area extends south from Lake Macquarie to Broken Bay/Brisbane Water. Most of the development in the area has occurred in a coastal strip to the east of the M1 Pacific Motorway. Development is bound by bushland to the West of the region, and water to the north, south and east. The coastal area of the Lower Central Coast is a popular holiday destination and is a dormitory suburb for Sydney. The area is currently a mix of rural, residential, commercial and industrial land use. The major industries in the area are coal mining and power generation, both of which are in the northern part of the area. The Department of Planning’s Regional Strategy for the Central Coast predicts continued population growth in the area over the next 15 years. 41,500 additional dwellings are expected in the area in the period to 2036, mostly as a result of in-fill development. As the population grows, industries in the region are likely to generate an increase in the number of jobs in wholesaling, retailing, property and business services, tourism, health services, cultural and recreational services and personal services. Although manufacturing jobs will increase in total numbers, the proportion of manufacturing jobs will decline. Development in the area is currently constrained by water supply issues, which prevent development of extensive areas of land west of the Sydney to Newcastle motorway. Greater population growth may be possible if the water supply issues are resolved. Ausgrid’s Central Coast transmission system comprises a network of 132kV lines running from north to south along the length of the Central Coast. The system interconnects TransGrid’s 330/132kV supply points at Vales Point and Munmorah in the north of the area with TransGrid’s centrally located Tuggerah 330/132kV supply point in the south. The network extends south from Tuggerah Bulk Supply Point (BSP) through the lower Central Coast, and connects to the inner metropolitan network at Mt Colah STSS. The Central Coast 132kV network: • provides 132kV supply to four zone substations and three STSs in the area; • supports the TransGrid owned 330/132kV substations at Tuggerah and Munmorah, with Munmorah BSP currently provide only non-firm supply; • operates in parallel with TransGrid’s 330kV system, linking major power stations on the upper Central Coast area with the Sydney metropolitan area. This means that power flows in the 132kV system are influenced by the configuration of the 330kV system; • has no 132kV busbar at Vales Point bulk supply point although there are two 330/132kV transformers • has no 132kV busbar at Munmorah 330/132kV BSP; and • requires substantial work to establish a 132kV busbar if any additional 132kV feeders were to be connected to either Munmorah or Vales Point BSP. Only those projects with a proposed implementation date within 10 years are included.

Figure 6.3: Identified system limitations in Central Coast 132kV load area

6.3.2 Identified system limitations Substation/ System limitation Load Impact on Discussion of Potential Credible Feeder reduction Transmission- Solutions name for 1 year Distribution Timing Driver deferral Connection (MVA) Points Nil

6.3.3 Identified Feeder limitations changes from last year’s DTAPR - deferred or committed projects Substation/F System Limitation Reason for Change eeder Name Timing Driver

Nil

6.3.4 Changes in dual function asset status No changes since the publication of the December 2019 DTAPR 6.3.5 Dual function connection points 6.3.5.1 Augmentation of existing dual function connection points Ausgrid has not identified any constraints to the capacity of existing dual function connection points in the next 10 years. 6.3.5.2 Committed new dual function connection points No committed projects since the publication of the December 2019 DTAPR.

6.4 Transmission load area – Lower Hunter 6.4.1 Description of Lower Hunter 132kV transmission load area Ausgrid prepares a Lower Hunter transmission load area plan that covers all Ausgrid 132kV subtransmission assets and dual function assets supplying the Lower Hunter subtransmission load areas. It forms the basis for TransGrid – Ausgrid joint planning and the sharing of network models and data in the Lower Hunter transmission area. The Lower Hunter region supplied by Ausgrid’s 132kV network extends from the Tomaree Peninsula and Karuah in the north, to Wyee and Swansea in the south. It is bordered on the east by the coastline and extends north- west to Pokolbin and south-west to Mandalong. The Lower Hunter 132kV network provides supply to the Ausgrid network serving Cessnock, Lake Macquarie, Maitland, Newcastle and Port Stephens local government areas; and connection between TransGrid’s 330/132kV bulk supply points in the Lower Hunter and TransGrid feeders supplying Essential Energy’s Lower North network. The Lower Hunter 132kV transmission network provides 132kV supply to the following Ausgrid network areas: • Newcastle Inner City • Newcastle Ports • Newcastle Western Corridor • North-East Lake Macquarie • West Lake Macquarie • Port Stephens • Maitland • Greater Cessnock. Ausgrid has prepared separate area strategy documents for each of these network areas; these documents set out the supply strategies for each area. The Lower Hunter 132kV Transmission network: • comprises around 300km of predominantly overhead 132kV feeders; • is supplied from the TransGrid transmission network Bulk Supply Points (BSP) at Killingworth (named Newcastle BSP), Waratah West and Tomago; • provides 132kV transmission connections from Tomago BSP to TransGrid feeders supplying the Essential Energy network at Taree and Stroud; • includes 132kV network interconnections to the Upper Hunter 132kV network at Rothbury and the Central Coast 132kV network via Morisset and Eraring substations; • provides 132kV supply connections for the OneSteel manufacturing facilities at Mayfield North and the Hydro Aluminium Smelter near Kurri Kurri (which ceased operations in 2013); and • includes nine 132/33kV subtransmission substations and thirteen 132/11kV zone substations.

Only those projects with a proposed implementation date within 10 years are included.

Figure 6.4: Identified system limitations in Lower Hunter transmission area

6.4.2 Identified system limitations Substation/ System limitation Load Impact on Discussion of Potential Credible Feeder reduction Transmission- Solutions name for 1 year Distribution Timing Driver deferral Connection (MVA) Points 1. Awaba Jun- 2024 Asset N/A None Credible Solutions include: 132/33kV Condition 1. Refurbish substation and STS (33kV consolidate assets (limitation Switchgear) 2. Construct Awaba 33kV advanced ) Switching Station 3. Defer refurbishment of Awaba STS via demand management Probabilistic Planning Assessments have shown there is net economic benefit for either credible solution based on the probability of failure, resulting load at risk, safety risk and maintenance of the 33kV switchgear An assessment of non-network options concluded that it is not considered probable that sufficient

Substation/ System limitation Load Impact on Discussion of Potential Credible Feeder reduction Transmission- Solutions name for 1 year Distribution Timing Driver deferral Connection (MVA) Points demand management measures could be feasibly implemented to achieve the required demand reduction to make the project deferral and economically viable. Note that the assessment was based upon preliminary assumptions for project costs, unserved energy and other benefits with a more detailed assessment to be conducted as part of the Regulatory Investment Test.

6.4.3 Identified System limitations changes from last year’s DTAPR - deferred or committed projects Substation/F System Limitation Reason for Change eeder Name Timing Driver

Nil

6.4.4 Changes in dual function asset status No changes since the publication of the December 2020 DTAPR 6.4.5 Dual function connection points 6.4.5.1 Augmentation of existing dual function connection points Ausgrid has not identified any constraints to the capacity of existing dual function connection points in the next 10 years. 6.4.5.2 Committed new dual function connection points No committed projects since the publication of the December 2019 DTAPR 6.5 Sydney Inner Metropolitan transmission load area 6.5.1 Description of Sydney Inner Metropolitan transmission load area Ausgrid prepares a Sydney Inner Metropolitan Transmission Load Area plan that covers all Ausgrid 132kV subtransmission assets and dual function assets which operate in parallel and support the main TransGrid transmission network in the Sydney Metropolitan subtransmission load areas. It forms the basis for TransGrid – Ausgrid joint planning and the sharing of network models and data for the Sydney Metropolitan transmission area. Joint planning activities with Transgrid are discussed in greater detail in Section 8.1 of this report. The Sydney Inner Metropolitan 132kV transmission network provides 132kV supply to the following Ausgrid network load areas: • Camperdown and Blackwattle Bay load area • Canterbury Bankstown load area • Carlingford load area • Eastern Suburbs load area • Inner West load area • North West Sydney load area • St George load area

• Sutherland load area • Sydney CBD load area.

The Sydney Inner Metropolitan transmission network supplies most of the eastern part of the Sydney metropolitan area. The load area extends from the Pacific Ocean, west to Ryde and Auburn, and is bounded to the south by the Royal National Park and to the north by the Hawkesbury River, but excludes the area east of the Lane Cove River valley. The Inner Metropolitan transmission system is defined as TransGrid’s 330kV cables 41 and 42, and the 330/132kV substations at Beaconsfield, Haymarket, Rookwood Road, Sydney North and Sydney South, together with Ausgrid’s 132kV dual function network that links those supply points. Total demand within the area amounts to more than 4,000MW. Sydney North and Sydney South Bulk Supply Point substations are strongly connected to the main NSW 330kV transmission network, and TransGrid makes firm 132kV capacity available at both locations. Beaconsfield and Haymarket substations are supplied by a single 330kV cable each, and Ausgrid’s interconnected 132kV dual function network provides the necessary connections to provide supply redundancy from these substations. This integrated supply arrangement has been in place since the mid-1970s and has been progressively developed through joint planning between TransGrid and Ausgrid. It represents the least cost solution to meet existing capacity requirements while providing the greatest potential to maximise the utilisation of all network assets. Following the commissioning of Rookwood Road BSP, the Sydney North 132kV network has completely been separated via open points from the remaining 132kV system due to fault level limitations. However, to support the remaining meshed 330kV and 132kV network, there remains the opportunity to transfer some load between the northern and southern 132kV networks via these open points. Only those projects with a proposed implementation date within 10 years are included.

Figure 6.5: Identified limitations in Sydney Inner Metropolitan transmission load area

6.5.2 Identified system limitations

Substation/ System limitation Load Impact on Discussion of Potential Credible Feeder name reduction Transmissio Solutions for 1 year n- Timing Driver deferral Distribution (MVA) Connection Points 1. Feeder 265 – Jun-22 Asset Condition NA None The Regulatory Investment Test for Bunnerong Distribution (RIT-D) was completed for this STSS to project in June 2020. Maroubra ZS The project assessment report considered two credible network options and non- network alternatives. It was determined that the option with the highest net market benefits was the like-for-like replacement of oil-filled cables with XLPE, with inclusion of a spare duct to reduce the cost of installing a future feeder between Bunnerong STSS and Kingsford ZS or to another ZS beyond there.

The draft and final project assessment reports and notice of non-network options can be found on Ausgrid’s website at https://www.ausgrid.com.au/ritd under “Addressing reliability requirements in the Maroubra area”.

2. Feeder 928/3 Sep-23 Asset Condition NA None Credible solutions include: and 929/1 – Lane Cove STS 1. Like-for-like replacement by to Dalley St ZS replacing oil-filled cables with XLPE;

2. Retirement of 928/3 and 929/1 feeder – part of Powering Sydney’s Future (PSF) Strategy, please refer to PSF for more detail;

3. Defer retirement or replacement of feeder 928/3 & 929/1 via demand management.

Assessment for non-network solutions was completed as part of the joint planning process with TransGrid for the Inner Metro Transmission network as part of Powering Sydney Future Strategy.

This process concluded that non-network solutions could form part of the least cost solution. Refer to TransGrid’s website at www.transgrid.com.au for details on the assessment and next steps.

3. Feeder 264 – Mar-25 Asset Condition NA None Credible solutions include: Beaconsfield

2. Retirement of feeder 264 by transferring Maroubra and Kingsford ZS loads to surrounding zones;

3. Defer replacement or retirement of feeder 264 via demand management of Maroubra and Kingsford zone loads.

4. Feeder 9FF Post Asset Condition NA None Credible solutions include: (ex 91M/3) – 2025 Beaconsfield to 1. Like-for-like replacement by Bunnerong replacing oil-filled portions with XLPE;

2. Retirement of 132kV 9FF;

3. Defer replacement or retirement of 132kV feeder via demand management.

Substation/ System limitation Load Impact on Discussion of Potential Credible Feeder name reduction Transmissio Solutions for 1 year n- Timing Driver deferral Distribution (MVA) Connection Points 5. Feeders 9SA Post Asset Condition NA None Credible solutions include: & 92P – 2025 Beaconsfield 1. Like-for-like replacement by replacing oil-filled portions with BSP to XLPE; Campbell St ZS and Belmore 2. Remediation of the cable section Park ZS Wellington St, Redfern initially and replacement of remaining oil-filled portions at a later date;

3. Defer replacement or retirement of 132kV feeder via demand management.

6. Feeder 202 – Post Asset Condition NA None Credible solutions include: Drummoyne ZS 2025 to Rozelle STS, 1. Like-for-like replacement of feeder and Drummoyne 202 followed by like-for-like ZS 132kV replacement of feeders 203 and switchgear 204;

2. Like-for-like replacement of feeder 202 followed by replacement of feeders 203 and 204 with a single feeder;

3. Like-for-like replacement of feeders 202 and 203 followed by replacement of feeder 204 via Burwood ZS and a new feeder between Burwood and Croydon ZSs;

4. Defer replacement or retirement of 132kV feeder via demand management of Drummoyne loads.

Credible solutions all include replacement of 132kV switchgear at Drummoyne ZS at the same time as 132kV cable connections at this site.

Substation/ System limitation Load Impact on Discussion of Potential Credible Feeder name reduction Transmissio Solutions for 1 year n- Timing Driver deferral Distribution (MVA) Connection Points An assessment of non-network options concluded that it is not considered probable that sufficient demand management measures could be feasibly implemented to achieve the required demand reduction to make the project deferral technically and economically viable.

7. Feeder 203 & Post Asset Condition NA None Credible solutions are investigated in 204 – Mason 2025 combination with the feeder 202 (item 6). Park STSS to Drummoyne ZS

6.5.3 Identified Feeder limitations changes from last year’s DTAPR - deferred or committed projects Substation/Feeder Name System Limitation Reason for Change Timing Driver Feeder 260/1 and 261/1 – Dec- Asset Condition Now reported in Chapter 5 as they are Beaconsfield BSP to Zetland 2026 distribution assets but deferred outside of 5 year reporting period for distribution assets due to reduced load forecast Feeder 91X and 91Y – Post Asset Condition Deferred from “post 2024” due to deferral of Beaconsfield BSP to Chullora 2030 TransGrid’s Powering Sydney’s Future Stage 2 STSS via Marrickville ZS project. Feeder 92C and 92X – St Peters Post Asset Condition Deferred from “post 2024” due to deferral of to Chullora STSS 2030 TransGrid’s Powering Sydney’s Future Stage 2 project. Feeder 9S2 – Beaconsfield BSP Post Asset Condition Deferred from “post 2024” due to deferral of to Haymarket BSP 2030 TransGrid’s Powering Sydney’s Future Stage 2 project. Feeder 90T/1 – Haymarket BSP Post Asset Condition Deferred from “post 2024” due to deferral of to Green Square ZS 2030 TransGrid’s Powering Sydney’s Future Stage 2 project. Feeder 270 – Kingsford ZS to Post Asset Condition Deferred from “post 2024” due to reduced load Maroubra ZS 2030 forecast

6.5.4 Changes in dual function asset status No changes since publication of the 2019 DTAPR. 6.5.5 Dual function connection points The following section details dual function projects that are driven by network constraints. 6.5.5.1 Completed new dual function connection points

This section describes augmentations that have been completed since the publication of 2019 DTAPR. Strathfield South 132/11kV zone substation: The energisation of the high voltage busbar, switchgear, feeder connections and power transformers was completed in late 2020. Load transfers from Enfield 33/11kV zone substation are currently underway. 6.5.5.2 Proposed augmentation of existing dual function connection points Ausgrid has not identified any constraints to the capacity of existing dual function connection points in the next 10 years. 6.5.5.3 Committed new dual function connection points Ausgrid has identified committed new dual function network connection points as tabulated below.

Region Proposal Purpose Timing

Sydney Macquarie 132/33kV Supply new customers in Macquarie Apr-22 Subtransmission Park area Substation

6.6 Frequency control and load shedding Emergency control schemes exist to make decisions in different situations so as to prevent the system from experiencing undesired conditions, and in particular to avoid large catastrophic disturbances. As a transmission network service provider, Ausgrid has implemented various control schemes for maintaining system security. Some emergency control schemes that have been implemented or proposed to be implemented are described as below. • Network switching and splitting to prevent circuits tripping due to thermal overloading as a preventive measure to ensure frequency control within limits; • Under frequency load shedding schemes have been implemented at most zone and subtransmission substations. They will be implemented on existing substations when an opportunity arises during augmentation or replacement works; and • Joint planning between Ausgrid and TransGrid to identify and implement load shedding schemes as per the connection agreement. 6.7 Stability As per NER S5.1.8, the network service provider must ensure and endeavour for stable operation of the national grid in following three stability aspects. • The power system will remain in synchronism. No generators or major augmentations were commissioned during this period that will affect the power system synchronism. Ausgrid cooperates with TransGrid to ensure that the power system remains in synchronism by sharing necessary network data as part of the joint planning process. • Damping of power system oscillations will be adequate. No generators or major augmentations were commissioned during this period that will affect the damping of power system oscillations. Ausgrid cooperates with TransGrid to ensure that the damping of power system oscillations will be adequate by sharing necessary network data as part of the joint planning process. • Voltage stability criteria will be satisfied. It is important to maintain voltage stability by keeping voltage within acceptable levels during normal operating conditions as well as following the loss of a single network element in the power system. The single element includes a transmission line, a cable, a transformer, a reactive support plant or a generator. Ausgrid performs QV analysis regularly to ensure that there is adequate reactive margin at each 132kV bus in Ausgrid’s network. As necessary, Ausgrid considers providing reactive support by way of installing shunt reactors and capacitors in suitable locations in the Ausgrid network. The current QV analysis has indicated that reactive margin is sufficient for all the buses in Ausgrid network.

7 Network investments

7.1 Regulatory investment tests 7.1.1 Completed during the year The following Regulatory Investment Tests for Distribution (RIT-D) have been completed in 2020. Cost estimates are in real dollars, as reported in the documents available in Ausgrid’s website at the following link: https://www.ausgrid.com.au/Industry/Regulation/Network-planning/Regulatory-investment-test-projects.

Date of Expected Project Estimated Region Constraint Project Name RIT-D Completion Cost ($m) completion Ensuring reliable Sydney Reliability supply for the Sydney 2023/24 6.6 06/04/2020 Airport network area Addressing reliability Asset Sydney requirements in the 2021/22 15.0 19/07/2020 Condition Maroubra load area

This project relates to capital works for network expansion. A summary is provided to describe the identified need Ausgrid is seeking to address, outline the credible network options considered and explain why other network options were disregarded, identify the proposed preferred option and explain the reasons for its selection. In addition, the summary includes the corresponding dates in which the different steps of the RIT-D process were completed. 7.1.1.1 Ensuring reliable supply for the Sydney Airport network area Sydney Airport ZS supplies the Sydney Airport domestic terminal as well as some of the airport’s commercial load (comprising over a hundred retail and commercial customers, including Qantas and Virgin Australia operations) through a network owned by the Sydney Airport Corporation Ltd (SACL) and provides back-up supply to the International Terminal via the 33kV switchboard. The 33/11kV transformers and 11kV switchgear at Sydney Airport ZS are owned by SACL whilst the 33kV switchgear is owned by Ausgrid. Electricity supply to Sydney Airport is provided via five 33kV cables from Bunnerong North STS to Sydney Domestic Airport and International Terminal 33/11kV zone substations. Whilst these cables are aged and there are condition issues associated with pilot cables, the feeders provide sufficient supply redundancy and therefore failures do not lead to loss of supply. However; there are condition issues with critical components at Sydney Airport ZS including the 11kV and 33kV switchgear used to control, protect and isolate electrical equipment. It has been determined that it would be cost effective to address the 33kV switchgear condition issues. SACL has initiated replacement works for the 11kV switchgear at their cost. Replacement of the 33kV switchgear in a new switchroom has been identified as the only option available to adress reliability risks based on the outcome of a RIT-D. Condition issues identified in the switchroom buildings have led to the decision to construct a new 33kV switchroom building at the customer’s cost to house the new equipment. The scope of this project includes the construction of a new building, installation of new equipment and retirement of the existing 33kV switchgear at Sydney Aiport ZS. Demolition of the existing building and site remediation will also occur as a result of the project. The new switchroom design will also support improved fire segregation, contributing to improved safety and reliability. The estimated capital cost of this option is $6.6 million. The refurbishment of the 33kV switchgear with new equipment in situ (i.e. ‘brownfield replacement’) was also considered under a staged approach. However, brownfield replacement imposes materially greater safety and schedule risk, arising from work being carried out next to energised equipment. Ausgrid also considered other options such as the retirement of the 33kV switchgear or the construction of a new 132/11kV zone substation, but these options were not progressed since they were found technically or commercially not credible. In the case of simple retirement, the reliability of supply would be significantly reduced and future developments in Sydney Airport would be limited. In the case of the new substation, the cost would be materially higher than replacing the switchgear, without providing a commensurate increase in benefits. A Final Project Assessment Report (FPAR) was published on 6 March 2020, presenting the assessment undertaken. A separate non-network screening notice was also released outlining that for this RIT-D, non-

network solutions were unable to form a standalone credible option, or form a significant part of a potential credible option. The 30-day dispute period ended on 6 April 2020 and no enquiries/disputes were received. Construction work commenced by end of 2019/20 following completion of the RIT-D assessment and subsequent project approvals. Subject to discussions to align the required work within Sydney Airport redevelopment works, the replacement of the 33kV switchgear is expected to be replaced by 2023/24. 7.1.1.2 Addressing reliability requirements in the Maroubra load area The Eastern Suburbs network area extends from South Head to La Perouse, inland to Surry Hills, and west as far as Marrickville. Within this area there is a 132kV network which supports the inner metropolitan transmission network. The underground 132kV electricity subtransmission cables (‘feeders’) commissioned in the 1960s and 1970s, are now reaching, or past, the end of their technical lives. In particular, the self- contained fluid filled (SCFF) feeders are now considered an obsolete and outdated technology. They are becoming less reliable and approaching the point at which their replacement maximises the net benefit for the community. Feeder 265 is a SCFF cable commissioned in 1979. It is approximately 3.8km long and connects Maroubra ZS with Bunnerong Subtransmission Switching Station (STSS). Its availability is critical to supplying zone substations connected to the ring in the event of an outage of any one of the other cables. While the current design ensures a level of redundancy, any outage on this feeder at the same time as an outage on Feeder 264 would result in the loss of supply to Kingsford ZS and Maroubra ZS, affecting up to 41,600 customers including the University of NSW, the Sydney Children’s Hospital and Prince of Wales Hospital, the Sydney Light Rail and the Royal Randwick Racecourse. To minimise the environmental risks of fluid leaks in SCFF feeders, Ausgrid has a program to replace all SCFF on its network with known leaks and this program has been provided to the Environmental Protection Authority. Replacement of Feeder 265 with modern cables forms part of this program by removing 3.8km of SCFF feeder from service. Two credible network options have been identified to address identified issues as part of a RIT-D: • Option 1 – Replacement of the existing Feeder 265 like-for-like; and • Option 2 – Replacement of Feeder 265 with spare duct to enable installation of future Bunnerong-Kingsford. As these credible options are part of broader strategies to address network risks associated with SCFF feeders in this network area, consideration has been given to include the cost of future works (i.e. network investments required to retire the SCFF Feeder 262 connecting Clovelly and Double Bay zone substations and the SCFF Feeder 270 connecting Maroubra and Kingsford zone substations). This is relevant to the assessment as one of the credible network options includes the addition of spare conduits for a marginal increase in cost that can facilitate the installation of a future feeder in the area at a materially lower cost than replacing the existing SCFF feeder alone. Replacement of Feeder 265 with spare duct to enable installation of future Bunnerong STS to Kingsford ZS has been identified as the preferred option as part of the broader strategy in the Eastern Subutbs. The scope of this project includes the installation of a new 132kV cable and spare conduits (for a second future feeder) from Bunnerong STSS to Maroubra ZS including civil works, to replace 132kV SCFF Feeder 265. The scope would be the same as for Option 1 with the addition of the installation of one spare duct line to accommodate a future second circuit in the same trench. The estimated capital cost of this option is $15.0 million. Ausgrid has considered one additional network option involving the decommissioning of the existing Feeder 265 and no works considered to replace the subtransmission feeder. However, this option was ruled out as it leaves Kingsford and Maroubra zone substations with only one source of supply. A Draft Project Assessment Report (DPAR) was published on 30 April 2020, presenting the assessment undertaken. A separate non-network screening notice was also released outlining that for this RIT-D, non- network solutions were unable to form a standalone credible option, or form a significant part of a potential credible option. The DPAR called for submissions from parties by 11 June 2020 and no submissions were received on either the DPAR or the separate non-network screening notice. A Final Project Assessment Report (FPAR) was then published on 19 June 2020, re-presenting the assessment undertaken in the DPAR. The 30-day dispute period ended on 19 July 2020 and no enquiries/disputes were received. Construction work commenced in 2020/21 following completion of the RIT-D assessment and subsequent project approvals. The replacement of Feeder 265 is expected to be completed towards the end of 2020/21. 7.1.2 In progress during the year This section describes the RIT-D assessments in progress, which remain open for consultation/disputes from market participants. Estimated costs are provided in real dollars, as reported in the documents available in Ausgrid’s website.

Expected Estimated Region Constraint Project Name Project Cost ($m) Completion Asset New Mascot East 132/11kV ZS and Sydney Dec-2024 38.8 Condition retirement of Mascot 33/11kV ZS

Asset Concord ZS 11kV switchgear Sydney 2023/24 14.2 Condition replacement

This project relates to capital works for network replacement or refurbishment. A summary is provided to describe the identified need Ausgrid is seeking to address, outline the credible network options considered and explain why other network options were disregarded, identify the proposed preferred option and explain the reasons for its selection. The summary also includes the corresponding dates in which the initial steps of the RIT-D process have been so far completed.

7.1.2.1 New Mascot East 132/11kV ZS and retirement of Mascot 33/11kV ZS The existing Mascot 33/11kV ZS has asset condition issues associated with its 11kV switchgear and the 33kV feeders supplying the substation. Of the five groups of 11kV switchgear at Mascot ZS, three of them are compound insulated and the remaining two groups are air insulated. A risk analysis has recommended immediete replacement of the 11kV switchboard at Mascot zone substation, as it offers economic benefits that exceed the annualised costs of replacing the asset. Potential credible options to address the issues above are: • Establishment of a new Mascot 132/11kV ZS and associated 132kV connections to replace the existing Mascot ZS and associated 33kV feeders; • Retirement of the existing Mascot ZS and associated 33kV feeders by transferring the 11kV load to neighbouring substations (i.e. Green Square ZS); • Partial retirement of the existing Mascot 33/11kV ZS by transferring a portion of the 11kV load to Green Square ZS and implementing risk mitigation measures on the remaining equipment at Mascot ZS; • Refurbishment of the existing Mascot ZS and replacement of the existing 33kV feeders with new XLPE cables from Bunnerong North STS; and • Refurbishment of the existing Mascot ZS and replacement of the existing 33kV feeders with new XLPE cables from Alexandria STS (currently in construction). All replacement options are currently under review. The expected completion date for the network option is December 2024, noting that a risk mitigation action is currently in progress to address issues with the deteriorating 11kV switchgear at Mascot ZS. A transfer of 11kV load from Mascot to Green Square ZS was completed in 2019 to mitigate the identified risk. This 11kV load transfer project was committed in December 2017. A Non-network Options Report was published on 23 September 2019 seeking demand management solutions to address the identified network need in relation to Mascot ZS. Submissions responding to the Non-network Options Report were able to be lodged until 23 December 2019. Five proposals were provided by non- network proponents in response to the Non-Network Options Report. Since then, a revised network solution has been proposed involving the partial removal of load from the existing Mascot ZS. The revised solution is undergoing feasibility assessment and may affect the feasibility of demand management at Mascot. . A DPAR will be prepared incorporating the latest available information on demand forecasts, VCR estimates, project cost estimates of the network and information about the proposed non-networl options. Ausgrid intends to publish the DPAR in 2021. Further consultation will then proceed in accordance with the RIT-D process set out in the Rules.

7.1.2.2 Concord ZS 11kV switchgear replacement Concord ZS is a 33/11kV zone substation located in the Sydney Inner West area of Ausgrid’s network. It was commissioned in 1955 and is supplied via four 33kV cables from Homebush STS predominantly with XLPE type with small sections of paper insulated cables near the substation site. The paper insulated cables are 62 years of age, but at present there are no known condition issues with these cables. Concord ZS comprises of three groups of double busbar compound insulated switchgear. The 11kV bulk oil circuit breakers (OCB) were replaced with vacuum units. However, the 11kV compound insulated switchboard is beyond its design life and considered obsolete, with an increasing reliability risk that could expose customers in the area to a level that exceeds applicable reliability standards. A failure of the switchboard may cause a fire,

which could lead to both loss of supply and severe damage to equipment and buildings, and ultimately result in safety hazards and extended outages. In addition, there are secondary systems such as the 11kV control and protection equipment and the voltage regulation scheme that are about to reach the end of their service life, and the oil containment system at this substation is not adequate to ensure compliance with modern day standards. Two credible network options have been identified to address identified issues: • Option 1 – Concord ZS refurbishment, which could involve temporary load transfers to adjacent zone substations while undertaking staged replacement of 11kV switchgear; and • Option 2 – Construction of a new switchroom building on the existing site and transfer the load from the old to the new switchgear to enable retirement of the aged 11kV switchgear. Other options considered but not progressed were the construction of a new zone substation (either 33/11kV or 132/11kV) on a greenfield site to replace the existing Concord 33/11kV ZS. These options were disregarded because the costs are considerably higher (in excess of $25 million each) than Options 1 and 2, without providing commensurate market benefits. Pending consideration of non-network options, Option 2 is the preferred solution, as it has the highest net market benefits. It involves the construction of a new switchroom building on the existing site to replace the existing 11kV switchgear and associated control and protection, noting that upgrades of the voltage regulation scheme and the oil containment system will be undertaken under corresponding replacement programs. The expected completion date for this project is August 2023.

A DPAR and Non-Network Options Report was published on 22 October 2020, incorporating the latest available information on demand forecasts, VCR estimates, project cost estimates of the network. The documents were opened for consultation until 03 December 2020 and no submissions were received. A FPAR was published on 11 December 2020, re-presenting the assessment undertaken in the DPAR. The 30-day dispute period will end on 10 January 2021. 7.1.3 For the forward planning period - Distribution This section describes the network investments for which a RIT-D assessment is expected to be initiated in 2020. Estimated costs are provided in real 18/19 dollars.

Expected Estimated Region Constraint Project Name Project Cost ($m) Completion Load Growth & Hunter Asset Tarro 11kV switchgear replacement Sep-2024 10.2 Condition Asset Milperra ZS 11kV switchgear Sydney Sep-2024 10.5 Condition replacement Asset Willoughby STS 33kV switchgear Sydney Dec-2025 35.1 Condition refurbishment

7.1.3.1 Tarro ZS 11kV switchgear replacement Tarro ZS is a 33/11kV zone substation located in the Maitland area of Ausgrid’s network. It was commissioned in 1960 and is supplied via two 33kV feeders from Beresfield STS. The compound-insulated 11kV switchgear has a deteriorating condition and is considered to be beyond its design life. Furthermore, new industrial developments in the area may lead to forecast demand exceeding the capacity to supply such requirements. Two options were considered to address the identified issues at Tarro ZS: • Option 1 – Tarro ZS refurbishment involving construction of a new switchroom building to house new 11kV switchgear; • Option 2 – Retirement of Tarro ZS via construction of a new zone substation. Other options considered but not progressed were the transfer of 11kV load to nearby existing zone substations followed by either Option 1 or Option 2. The retirement of Tarro ZS by transferring all 11kV load to existing nearby zone susbtations was disregarded because of required extensive 11kV augmentation to maintain adequate voltage levels and higher costs and longer delivery timeframes, without providing commensurate market benefits. Pending confirmation of new load requirements and consideration of non-network options, the preferred option at this stage is the replacement of 11kV switchgear by installing a new switchroom building within the existing

site and transfer the 11kV loads from the existing to the new switchgear. The expected completion date for this project is September 2024. 7.1.3.2 Milperra ZS 11kV switchgear replacement Milperra ZS is a 132/11kV zone substation located in the Canterbury Bankstown area of Ausgrid’s network. It was first commissioned in 1966 and is supplied via two 132kV feeders from Sydney South Bulk Supply Point. The compound-insulated 11kV switchgear is in poor condition and is considered to be beyond its design life. Two options are being considered to address the identified issues at Milperra ZS: • Option 1 - Load transfer to Bass Hill and uprate 33/11kV 15MVA Transformers at Bass Hill; • Option 2 – Replace the 11kV switchgear at Milperra ZS in-situ. A Value Management Study is expected to occur in late 2020 to assess the options available for the replacement of Milperra ZS 11kV switchgear based on the latest demand forecast and planning methodologies. Pending confirmation of new load requirements and consideration of non-network options, the preferred option at this stage is the replacement of 11kV switchgear by installing a new switchroom building within the existing site and transfer the 11kV loads from the existing to the new switchgear. The expected completion date for this project is September 2024. 7.1.3.3 Willoughby STS 33kV switchgear refurbishment Willoughby STS is a 132/33kV subtransmission substation located in the Lower North Shore area of Ausgrid’s network. It was commissioned in 1968 and is supplied by four 132kV cables from TransGrid’s Sydney East 330/132kV Bulk Supply Point (BSP) via Ausgrid’s Lindfield 132kV Subtransmission Switching Station (STSS). Most of the 33kV bulk oil switchgear is considered to be close to the end of its service life. In particular, there have been failures in the 33kV wall bushings due to their poor condition, with explosive failure modes attributed to degraded insulation quality. The 33kV isolators and earth switches are also in poor condition, with an operating system that requires manual operation through a series of drive rods and linkages. In addition, the 33kV switchroom building and control room roof is in poor condition. In the event of fire, the building’s physical structure does not allow contemporary levels of segregation within the switch room building. Furthermore, new industrial developments in the area may lead to augmention of the network to be able to supply such requirements. The substation supplies Chatswood and Gore Hill Zone substations as well as a number of major subtransmission customers including the Sydney Metro North West, Sydeny Metro City & South West. a number of data centres and the Gore Hill Technology Park. One credible option has been identified to address the identified issues at Willoughby STS. It involves replacement of the 33kV circuit breakers and associated secondary equipment in a new building on a vacant portion of the existing site, and demolition of the existing building. The other option which was considered but not progressed was the like-for-like replacement of all existing 33kV switchgear within the existing building and refurbishment of existing structures at Willoughby STS. This option is not considered feasible due to unavailability of some of the assets such as the dead tank transformer and bus section circuit breakers at the required ratings for procurement from any manufacturer. Pending confirmation of new load requirements and consideration of non-network options, the preferred option at this stage is the replacement of 33kV switchgear by installing a new switchroom building within the existing site and transfer the 33kV feeders from the existing to the new switchgear. The expected completion date for this project is December 2025.

7.1.4 Longer term constraints and indicative developments – Distribution The following section provides an overview of network investments in the distribution network that are expected to initiate a RIT-D assessment during 2021 and beyond. The list includes indicative developments that may be initiated within the 2020-25 period. Estimated costs of the proposed network investments are provided in real 18/19 dollars.

Expected Estimated Region Constraint Indicative Development Project Cost ($m) Completion Asset Managing asset risks in the West Lake Hunter Jun-2024 6.5 Condition Macquarie network area

Expected Estimated Region Constraint Indicative Development Project Cost ($m) Completion Asset Sydney Blakehurst 33kV ZS decommissioning Sep-2026 19.9 Condition Asset Botany ZS 11kV switchgear (Group 1) Sydney Sep-2026 5.9 Condition replacement Asset 132kV Feeders 923/2 & 924/2 Mason Sydney Sep-2027 9.5 Condition Park STSS – Burwood ZS replacement Asset Leightonfield ZS 11kV switchgear Sydney Sep-2028 7.6 Condition replacement Asset Riverwood ZS 11kV switchgear Sydney Sep-2028 12.3 Condition replacement Asset 132kV Feeder 202 Rozelle STS – Sydney Sep-2028 15.9 Condition Drummoyne ZS replacement Asset 132kV Feeders 203 & 204 Mason Park Sydney Sep-2028 32.2 Condition STSS – Drummoyne ZS replacement Asset Drummoyne ZS 132kV switchgear Sydney Sep-2028 15.6 Condition replacement

7.1.4.1 Managing asset risks in the West Lake Macquarie network area Awaba 132/33kV STS is located in the West Lake Macquarie area of Ausgrid’s netowrk. It was commissioned in 1960 and much of the equipment is still original. Awaba STS is an entirely outdoor substation which, after the commissioning of Toronto West 132/11kV ZS, supplies industrial load. The supplied load consists of several major customers (mine developments) and a railway supply. The deteriorating condition of multiple assets (132kV transformers & switchgear, 33kV switchgear, control & protection, instrument transformers and the building) indicates that retirement or replacement is required. All original 33kV circuit breakers (14x33kV outdoor bulk-oil circuit breakers) and associated isolators and earth switches (28 in total) have surpassed their service life and are considered to be in poor condition. Pending consideration of non-network options, the refurbishment of Awaba STS is the preferred option. The expection completion date of this project is June 2024. The project involves the retirement of the 33kV switchyard and redundant feeders at Awaba STS and a new re-arrangement of the 33kV switch yard to supply the major customers in the area (i.e. two mine developments and the State Rail Authority).

7.1.4.2 Blakehurst 33kV ZS decommissioning The 11kV switchgear at this zone substation is compound insulated and is in poor condition. In addition, the 33kV bulk oil circuit breakers and 33kV Essantee isolator switches are estimated to have reached the end of their serviceable life and some parts of the 33kV busbar do not comply with current clearance requirements. Furthermore, the 33kV feeders between Peakhurst Subtransmission Substation (STS) and Blakehurst ZS are gas pressure cables and approaching the end of their service life. Therefore, it is proposed to decomission Blakehurst ZS by transferring load from Blakehurst ZS load to surrounding zone substations. The cost benefit analysis indicates the optimal timing for these works is by September 2026. 7.1.4.3 Botany ZS 11kV switchgear (Group 1) replacement The compound-filled 11kV switchgear at Botany ZS present a high fire risk, because the bituminous compound can act as a fuel source in the event of simple outages. Considering its deteriorating condition and age, the 11kV switchgear replacement at Botany ZS was staged into two stages. The first stage of replacing Group 2 and Group 3 11kV switchgear is committed and is expected to complete in 2019. As the second stage of the replacement, Group 1 switchgear are planned to be replaced by September 2026. 7.1.4.4 132kV feeders 923/2 & 924/2 Mason Park STSS – Burwood ZS replacement The 132kV feeders 923/2 and 924/2 supply Burwood ZS from Mason Park STSS. Commissioned in 1976, these feeders are oil filled cables with approximately 1.6km in length. 923/2 has experienced oil leaks over the past 15 years. With their age and deteriorating condition, it is recommended to replace them like for like with a modern XLPE cable on a similar route. This replacement project is expected to be completed by September 2027.

7.1.4.5 Leightonfield ZS 11kV switchgear replacement The 11kV compound switchgear at Leightonfield ZS was approaching the end of its service life and was prioritised for replacement. The 11kV circuit breakers panel 1-4 are already decommissioned and loads have been distributed to the remaining panels in the same zone. The probability based cost benefit analysis indicates the optimal timing to replace the remaining panels on a new site adjacent to existing Leightonfield ZS is September 2028. 7.1.4.6 Riverwood ZS 11kV switchgear replacement The 11kV switchgear at this zone substation is compound insulated and is in poor condition. The probability based cost benefit analysis indicates the optimal timing to replace the switchgear is September 2028. 7.1.4.7 132kV feeder 202 Rozelle STS – Drummoyne ZS replacement The 132kV cable 202 between Rozelle STS and Drummoyne ZS is approximately 3.8km long and is fluid- filled, with a submarine crosing of Iron Cove. Commissioned in 1977, the feeder 202 poses a risk of deteriorating reliability, and crosses Parramatta River, which is an environmentally sensitive area. It is recommended to replace feeder 202 with modern equivalent technology (i.e. a single XLPE cable) by September 2028. 7.1.4.8 132kV feeders 203 & 204 Mason Park STSS – Drummoyne ZS replacement The existing 132kV feeders 203 and 204 from Mason Park STSS to Drummoyne ZS are single core 1000mm2 oil-filled cables. Commissioned in 1980, these feeders have experienced moderate iol leaks over the past 15 years. Testing indicates that there may be problems with the outer serving of the cables which could lead to oil leaks in the future. A number of options were considered to address this issue and the most likely option is to replace feeders 203 and 204 by September 2028. 7.1.4.9 Drummoyne ZS 132kV switchgear replacement The gas-insulated 132kV switchgear at Drummoyne ZS was commissioned in 1979 and is in deteriorating condition. The most economic option is to construct a new 132kV switchroom on the site adjacent to the existing Drummoyne ZS and install new 132kV switchgear. Then the transformers and feeders can be transferred to the new 132kV switchgear to allow retirement of the existing gas insulated switchgear. To enable construction efficiences, the replacement of the switchgear is recommended to be aligned with the replacement of feeders 202, 203 and 204. It is recommended to complete these works by September 2028, however proposed developments in the area may make other options viable. 7.1.5 For the forward planning period – Dual Function This section describes the augmentation and replacement driven projects for which a RIT-T assessment is expected to be initiated in 2020. Estimated costs are provided in real 18/19 dollars.

Expected Estimated Region Constraint Project Name Project Cost ($m) Completion Asset 132kV Feeder 264 Beaconsfield BSP – Sydney Mar-2025 26.3 Condition Kingsford ZS replacement

7.1.5.1 Replacement of 132kV Feeder 264 between Beaconsfield BSP and Kingsford ZS Feeder 264 is an oil-filled underground cable, approximately 5.5km long, which was installed in 1977. The oil- filled cable have been identified as approaching the end of its service life. A risk assessment has determined the need to replace this cable by March 2025. The preferred option is to replace the oil-filled cable sections with XLPE cable utilising a spare duct installed with Feeder 265. This project assumes the replacement of Feeder 265 has been completed.

7.1.6 Longer term constraints and indicative developments – Dual Function The following section provides an overview of dual function network assets that are expected to initiate a RIT-T assessment during 2021 and beyond. The list includes indicative developments that may be initiated within the next 10 years. Estimated costs are provided in real 18/19 dollars.

Expected Estimated Region Constraint Indicative Development Project Cost ($m) Completion Asset New Waterloo 132/11kV ZS and Sydney Condition retirement of Zetland 132/11kV ZS Dec-2026 40.4 Asset 132kV Feeders 260/1 and 261/1 Sydney Condition decommissioning

132kV Feeder 9FF Beaconsfield BSP – Asset Sydney Bunnerong STSS oil section Sep-2028 16.3 Condition replacement 132kV Feeders 9SA & 92P Asset Sydney Beaconsfield BSP to Campbell St Sep-2028 28.9 Condition ZS/Belmore Park ZS

7.1.6.1 New Waterloo 132/11kV ZS and retirement of Zetland 132/11kV ZS The project is to establish a new Zone Substation in the vicinity of Alexandria North in the Eastern Suburbs area of Ausgrid’s network. The need is expected to arise because of growth concentrated in the “Central to Eveleigh Precinct” area that is being managed by Urban Growth NSW Government agency. Area growth is also driven by the development of a Metro Station at Waterloo as part of a new rail corridor, and the establishment of new Information Technology based facilities. The new zone substation, which could be named Waterloo or Alexandria North, would also assist in achieving the retirement of the ageing Zetland ZS and its oil-filled cables originated from Beaconsfield BSP (132kV feeders 260/1 and 261/1). Allowing for new loads being connected to Green Square in the short term, the need for this substation is expected to arise by December 2026. The proposed location will be close to the route of a 132kV cable that will replace the oil-filled cable 9SA. Thus there will be minimal cable cost if the new substation is connected to this cable. Other potential credible options could include 11kV connections to neighbouring zone substations such as Green Square ZS. Consideration will be given to the possibility of installing 33kV connections or implementation of non-network options to defer investment in a new substation to align with the retirement of Zetland ZS. 7.1.6.2 132kV Feeder 91M/3 Beaconsfield BSP – Bunnerong STSS (oil section) replacement Feeder 91M/3 is approximately 9.3km long and was installed in 1973. A section of this feeder is currently being replaced, between Bunnerong STSS and Mill Pond Rd, Botany. The remaining section, from Mill Pond Rd to Beaconsfield BSP, when considered in isolation, is recommended for replacement in the period 2024-29. Taking into account, synergies between this feeder replacement and other projects suggest that it is cost effective to bring forward the replacement of feeder 91M/3 remaining section to coordinate with the project to replace the existing Mascot ZS. Replacement options are still under consideration, however the most likely option is to replace the oil-filled cable section by September 2028. 7.1.6.3 132kV Feeders 9SA & 92P Beaconsfield BSP – Belmore Park/Campbell St ZS replacement 132kV feeder 9SA from Beaconsfield BSP to Campbell St ZS, and 132kV feeder 92P from Beaconsfield BSP to Belmore Park ZS are oil-filled underground cables commissioned in the 1970s. These cables are approximately 5.7km and 5.5km long respectively. The risk assesment recommends the replacement of these feeders in the period 2024-29, taking into account the history of oil leaks, failures and increased rates of corrective works. As part of the State Government’s WestConnex motorway project, Roads and Maritime Services (RMS) is widening Euston Road between Campbell Road and Maddox Street, Alexandria. WestConnex is also replacing a 1.6km section of feeders 9SA and 92P. As a result, the cost of replacing the SCFF feeders has been significantly reduced, and the resulting cost benefit analysis update has recommended advancing the replacement of remaining sections to the 2020-24 regulatory period. Ausgrid initiated a partial replacement of an additional 1.0km section as a result of the relocation triggered by the WestConnex project. This decision was taken to achieve construction efficiencies and avoid significant

additional costs of replacing the cables in roads with increased traffic flows. These early works were committed for completion in 2018/19. Replacement of the remaining 3.0km sections are still under consideration, however the most likely option is to replace the remaining oil-filled cable sections with XLPE cables. The expected completion date for this project is September 2028.

7.1.7 Not proceeding – Distribution The table below shows the projects associated with distribution assets identified in the preceding DTAPR which are now not expected to proceed to the RIT-D assessment process in the next five years.

Region Project Previous Reason for cancellation/deferral or RIT- Need Date D not proceeding Non-network solutions were Darlinghurst ZS 11kV identified and will enable deferral Sydney load transfers and Sep-2026 of this project from 2026 to substation retirement 2029.

An updated risk-based cost-benefit 33kV Feeders 380, 381 analysis indicates that the benefits of & 382 Surry Hills STS- Sydney Mar-2029 reduced unserved energy do not exceed Paddington ZS the annualised cost of replacing the 33kV replacement feeders until 2029. An updated risk-based cost-benefit analysis indicates that the benefits of Pymble ZS 11kV Sydney Sep-2030 reduced unserved energy do not exceed switchgear replacement the annualised cost of replacing the 33kV feeders until 2030. An updated risk-based cost-benefit 33kV Feeders 383, 384 analysis indicates that the benefits of & 385 Surry Hills STS- Sydney Sep-2033 reduced unserved energy do not exceed Surry Hills ZS the annualised cost of replacing the 33kV replacement feeders until 2033. An updated risk-based cost-benefit 33kV Feeders 313, 318, analysis indicates that the benefits of 324 & 340 Bunnerong Sydney Mar-2035 reduced unserved energy do not exceed STS-Matraville ZS the annualised cost of replacing the 33kV replacement feeders until 2035. An updated risk-based cost-benefit Lidcombe ZS 11kV analysis indicates that the benefits of switchgear (Group 1) Sydney Sep-2036 reduced unserved energy do not exceed and associated 33kV the annualised cost of replacing the 33kV feeder replacement feeders until 2036. An updated risk-based cost-benefit Clovelly ZS 11kV analysis indicates that the benefits of Sydney switchgear (Group 2) Mar-2037 reduced unserved energy do not exceed replacement the annualised cost of replacing the 33kV feeders until 2037.

7.1.8 Not proceeding – Dual Function The following dual function asset augmentation or replacement projects described in the preceding DTAPR have either been deferred beyond the ten year forward planning period or cancelled.

Region Project Previous Reason for cancellation/deferral Need Date

An updated risk-based cost-benefit analysis 132kV Feeders 91A/1 & indicates that the benefits of reduced 91B/1 Beaconsfield BSP Sydney Sep-2032 unserved energy do not exceed the – St Peters ZS annualised cost of replacing the 132kV replacement cables until 2032. An updated risk-based cost-benefit analysis indicates that the benefits of reduced St Peters ZS 11kV Sydney Mar-2037 unserved energy do not exceed the switchgear replacement annualised cost of replacing the 11kV switchgear until 2037.

7.2 Completed or cancelled investments For the purposes of this document, a project is considered to be complete when it is commissioned and in service (practically complete). 7.2.1 Refurbishment, replacement or augmentations – Distribution The following distribution refurbishment or replacement projects described in DTAPR 2019 have either been completed or cancelled during the preceding year.

Completed or Cancelled Refurbishment or Load Area Reason / comments Replacement Investment - Distribution Canterbury – Bankstown STS 33kV switchgear replacement Completed Bankstown Canterbury – Sydney South to Revesby 132kV feeders Completed Bankstown replacement New 132kV Feeder Kingsford to Clovelly and Eastern Suburbs Completed decommissioning of Zetland-Clovelly 132kV feeders

Inner West Leichhardt ZS 132kV conversion Completed

Upper North Shore Kuringai STS 33kV switchgear replacement Completed

7.2.2 Refurbishment, replacement or augmentations – Dual Function The following dual function refurbishment or replacement projects described in DTAPR 2019 have either been completed or cancelled during the preceding year.

Completed or Cancelled Refurbishment or Load Area Reason / comments Replacement Investment - Distribution

Canterbury – Canterbury STS 132/33kV Refurbishment Completed Bankstown

Muswellbrook Singleton ZS 11kV switchgear replacement Completed

7.3 Committed investments Ausgrid has identified all committed refurbishment or replacement investments with an estimated capital cost of $2 million or more. Capital cost estimates are shown in nominal dollars and excludes contingency costs. 7.3.1 Refurbishment, replacement or augmentations – Distribution

Estimated Expected Committed Refurbishment or Replacement Cost Load Area Project Investment – Distribution (nominal Completion $m)

Convert Blackwattle Bay load from 5kV to 11kV Camperdown and and load transfer and retire 33/5kV Blackwattle May-22 16.5 Blackwattle Bay Bay ZS 11kV Load Transfer to enable retirement of Inner West Nov-20 7.5 Flemington ZS 11kV switchgear Group 1 Canterbury - New 132/11kV Greenacre ZS & decommission Nov-20 29.7 Bankstown Greenacre Park ZS Matraville ZS 11kV switchgear Groups 1, 2 and 4 Eastern Suburbs Feb-21 14.2 replacement

Eastern Suburbs Surry Hills ZS 11kV switchgear replacement Jul-22 18.1

Eastern Suburbs Decommission Darlinghurst 33/11kV ZS – Stage 1 Mar-22 3.9

Lidcombe 33/11kV ZS 11kV switchgear Group 2 Inner West Oct-21 6.7 replacement

Inner West Decommission 132/33kV Strathfield STS Apr-21 9.3

New Summer Hill 33/11kV ZS and associated Inner West 33kV feeders and decommission Dulwich Hill Feb-21 40.9 33/11kV ZS

Inner West Rozelle STS new 33kV switchgear Mar-22 22.7

Replace 33kV feeders – Homebush STS to Inner West Jul-23 31.3 Lidcombe ZS and Auburn ZS Willoughby to Mosman 132kV Feeders Lower North Shore Feb-21 35.4 Replacement

Newcastle Ports Waratah 132/33kV STS refurbishment Jun-22 17.0

St George Peakhurst STS 33kV switchgear replacement Jun-22 25.0

11kV Load Transfers from Dalley St ZS to City Sydney CBD Jun-21 18.9 North ZS Ensuring reliable supply for the Sydney Airport Eastern Suburbs Jan-24 8.6 network area

Port Stephens Stockton ZS 11kV switchgear replacement Jul-21 5.5

Upper Hunter Muswellbrook ZS Refurbishment Dec-21 3.3

Upper Hunter Muswellbrook STS Refurbishment Dec-21 5.6

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7.3.1.1 Convert Blackwattle Bay load from 5kV to 11kV and load transfers and retire Blackwattle Bay ZS Key project milestones: • Project initiated in November 2015. • Project expenditure authorised by Ausgrid Board in June 2017. • Project completion is expected by May 2022. Options Analysis Three network options were considered to resolve the above issues: Option 1 - Commission the 4th transformer at Camperdown zone substation and transfer Blackwattle Bay load to Camperdown zone substation This option involves: • 2016/17 – Surry Hills to Camperdown zone substation 11kV load transfer to facilitate 11kV switchgear replacement at Surry Hills zone substation; • 2017 – Commission the 4th transformer and associated 33kV feeder and install 11kV switchgear at Camperdown zone substation; • 2018 – Convert Blackwattle Bay zone substation load from 5kV to 11kV and transfer load to Camperdown zone substation; and • Three minor 11kV load transfer projects post 2028. The total Net Present Cost (NPC) of this option is $19.0 million. Option 2 - Transfer Blackwattle Bay load to Camperdown and Darling Harbour zone substations This option involves: • 2016/17 – Surry Hills to Campbell St zone substation 11kV load transfer to facilitate 11kV switchgear replacement at Surry Hills zone substation; • 2018 – Convert Blackwattle Bay zone substation load from 5kV to 11kV and transfer to Camperdown and Darling Harbour zone substations; • 2022 - Commission the 4th transformer and associated 33kV feeder and install 11kV switchgear at Camperdown zone substation; • 2022 – 10MVA 11kV load transfer Darling Harbour to Camperdown zone substation; and • Three minor 11kV load transfer projects post 2027. The total NPC of this option is $20.2 million. Option 3 – Transfer Camperdown load to Leichhardt zone substation and transfer Blackwattle Bay load to Camperdown and Darling Harbour zone substations This option involves: • 2016/17 – Surry Hills to Camperdown zone substation 11kV load transfer to facilitate 11kV switchgear replacement at Surry Hills zone substation; • 2018 – 8MVA load transfer from Camperdown to Leichhardt zone substation via switching; • 2018 – Convert Blackwattle Bay zone substation load from 5kV to 11kV and transfer load to Camperdown and Darling Harbour zone substations; • 2020 – 4MVA 11kV load transfer from Darling Harbour to Camperdown zone substation; • 2023 - Commission the 4th transformer and associated 33kV feeder and install 11kV switchgear at Camperdown zone substation; • 2023 – 8MVA 11kV load transfer Darling Harbour to Camperdown zone substation; and • Three minor 11kV load transfer projects post 2027. The total NPC of this option is $19.8 million. Given the low deferral value available for reducing demand and the scale of load reduction required it was determined that non-network options could not form part of a credible option for this replacement investment. The NPC results of the network options are considered equivalent given the accuracy of planning estimates. Option 3 is the recommended solution because it provides greater flexibility to address future growth in the Blackwattle Bay area, as several commercial and residential developments are likely to occur. In addition, it defers the need for the additional transformer at Camperdown zone substation until 2023.

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The project was approved by Ausgrid Board on 20/06/2017, at a total cost of $18.1 million ($16.5 million excluding contingency). The original completion date of the 11kV load transfers was September 2018, with decommissioning of Blackwattle Bay 33/5kV zone substation targeted for March 2019. Project complexities associated with staging/planning customer outages, night works and increased cable testing requirements have led to extend the project construction timeframe. Geographical view of works required in Blackwattle Bay project

7.3.1.2 11kV Load Transfers to enable retirement of Flemington ZS 11kV switchgear Group 1 Key project milestones: • Project initiated in June 2017. • Project expenditure authorised by Ausgrid Chief Executive Officer in August 2018. • Project completion is expected by November 2020. Options Analysis The 11kV switchgear at Flemington zone substation consists of both compound and air insulated types. Group 1 of 11kV switchgear at Flemington ZS uses bituminous compound insulation busbars (switchboard) and oil- filled circuit breakers. The presence of both oil and insulating compound creates a heightened fire risk in the event of failure and therefore this is regarded as obsolete technology. Three options have been considered to address issues with Flemington zone substation: Option 1 – Refurbishment of Flemington Zone Substation This option involves refurbishing Flemington zone substation, utilising the existing switchroom building. The 11kV loads would need to be transferred to other zone substations to allow the refurbishment work to take place. The Net Present Cost of this option is $23.6 million.

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Option 2 – Retirement of compound-filled 11kV switchgear at Flemington zone substation and replacement of Transformer 4 This option proposes the transfer of all Group 1 load at Flemington zone substation (approximately 42MVA) to adjacent Olympic Park zone substation and Auburn zone substation. Flemington zone substation 11kV switchgear Group 2 is to remain in operation and Tx3 will continue to be used in service but be physically moved to Flemington Tx2 bay, while Tx4 is to be replaced by a transformer made surplus by the reconfiguration of Clovelly zone substation. The Net Present Cost of this option is $7.7 million. Option 3 – Replacement of Flemington compound-filled 11kV switchgear and Transformers 2 and 4 This option involves replacement of compound filled 11kV switchgear and transformers 2 and 4, using a new switchroom. 11kV loads will need to be transferred to other zone substations to enable these replacements. The Net Present Cost of this option is $17.5 million. The preferred option is Option 1 as it is the least cost option. Options 2 and 3 were considered but not progressed, because their costs are significantly higher than Option 1 and do not provide a corresponding increase in benefits. A RIT-D assessment was completed for this project in 2018. The project was approved by the Chief Executive Officer on 21/08/2018, at a total cost of $9.4 million ($7.5 million excluding contingency).

7.3.1.3 New 132/11kV Greenacre Park ZS and decommission zone substation Key project milestones: • Project initiated in November 2013. • Project expenditure authorised by Ausgrid Board in June 2017. • Project completion is expected by November 2020. Options Analysis Nine options were investigated in detail. These options were costed using high level estimates following completion of concept drawings, development of staging and identification of risks.

Option Description Cost 1 New Greenacre Zone (2x50MVA and 3x132kV bus sections) $33.6M 2 Brownfield 11kV Switchgear + Greenfield Indoor 132kV GIS and new transformers $59.9M 3 Brownfield 11kV Switchgear + Greenfield Outdoor 132kV GIS and new transformers $56.1M 4 Brownfield using out 132kV Hybrid GIS and new transformers $50.8M 5 Brownfield using out 132kV Hybrid GIS using existing transformers $43.6M 6 Brownfield with tail ended 132kV using existing transformers $34.6M 7 Brownfield with DCB's using existing transformers $35.2M 8 Greenfield Substation 2x132kV bus sections and new transformers $32.7M 9 Greenfield 132kV Hybrid GIS, Brownfield 11kV switchgear using existing transformers $48.2M

Option 8 was discounted due to the additional network risk associated with having two rather than three bus sections and Option 6 was not considered an acceptable solution due to the reduced flexibility and network security of the tail ended arrangement. Consideration was also given to the possibility of decommissioning the existing Greenacre Park zone substation by transferring all 11kV loads to Bankstown zone substation. This option was not progressed because it requires extensive 11kV connections, as well as an additional 132/11kV 50MVA transformer; associated 132kV feeder and 11kV switchgear to be installed at Bankstown zone substation. The estimated cost of this option exceeded $44 million. The two remaining lowest cost alternatives (Options 1 and 7) have been analysed and compared in greater detail, with consideration given to construction time, staging, technical issues/constraints and costs including property resale. Option 1 – New Greenacre 132/11kV zone substation (2x50MVA) • New Greenacre zone substation adjacent to existing Greenacre Park zone substation. The existing substation would be decommissioned and the land would be available for sale.

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• Current forecasts indicate a load constraint in 2032 however the design can incorporate potential future expansion to meet this load. Option 7 - Greenacre Park Brownfield with DCBs (4x37.5MVA) • Staged Brownfield 11kV switchgear replacement within existing 11kV switchroom. Use of 11kV mobile switchroom to facilitate staging. • Replacement of existing control room and staged outdoor 132kV Isolators & Earthing Switches replacement with hybrid disconnector-circuit breakers. • Remediation of existing 11kV switch room building required to address condition issues. • Structural modification to the existing switchroom floor structural beam to accommodate replacement of 11kV switchgear and complete 11kV equipping. • Multiple 11kV load transfers required as part of the electrical staging. • Enables property sale of 222-230 Hume Highway, Greenacre.

Option 1 delivers a completely new 2x50MVA zone substation. The capacity of Option 1 would be less than Option 7 however expansion to meet potential future demands can be catered for. The purchase price of $3.9 million for the new site and an allowance of $1.5 million for the potential sale of the existing site have been included in the cost estimate of $33.6 million. Option 7 retains the existing 4 x 37.5MVA transformers arrangement and involves a staged 11kV switchgear replacement in the existing building plus a new control room. Implementation of this option is expected to take at least two years longer than Option 1. This option provides less network flexibility as no 132kV feeder circuit breakers would be installed and a mobile switchroom would need to be deployed at this location for several years. Pricing assumes internal delivery. The cost for this option is $35.2million and includes $3.9 million for the sale of the purchased site. Decommissioning of the 132kV feeders 291/1 and 292 has not been included, as this work is common to both options. Given the low deferral value available for reducing demand and the scale of load reduction required it was determined that non-network options could not form part of a credible option for this replacement investment. Option 1 is preferred because it has the lowest cost and can be delivered in a shorter timeframe than the refurbishment option. In addition, the new zone substation can achieve higher network reliability by providing increased switching flexibility than a brownfield development of the site. The project was approved by Ausgrid Board on 20/06/2017, at a total cost of $31.8 million ($29.7 million excluding contingency). This project was initiated in 2013 with a view to complete the works by December 2017. The project was delayed because a staged brownfield construction was identified during project development activities as a feasible alternative. A more detailed options analysis was then conducted and investigations were completed in early 2016, confirming the new zone substation as the preferred option.

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Plan view of the proposed Greenacre zone substation adjacent to the existing Greenacre Park ZS

7.3.1.4 Matraville 11kV switchgear Groups 1, 2 and 4 replacement Key project milestones: • Project initiated in May 2010. • Project expenditure authorised by Ausgrid Board in March 2017. • Project completion is expected by February 2021. Options Analysis Three options have been considered to address issues at Matraville zone substation: Option 1 – Retire Matraville via a new zone substation This option involves purchasing a site and greenfield construction of a new Matraville 33/11kV zone substation. Load would be transferred from the existing Matraville to the new zone substation. New 33kV feeders would need to be run from Bunnerong STS to allow retirement of the existing aged 33kV feeders. The estimated cost of this option is $39 million. The Net Present Cost (NPC) is $37 million. Option 2 – Retire Matraville via 11kV load transfer to surrounding zone substations This option involves transferring all loads to Port Botany and Maroubra zone substations to enable the retirement of Matraville ZS. The estimated cost of this option is $26 million and the NPC is $25 million. Option 3 – Replace Matraville 11kV switchgear and 33kV feeders This option involves staged replacement of the aged 11kV switchgear with fixed-pattern single bus switchgear. Transformer 3 will be permanently decommissioned due to their poor condition. In this option, the replacement of the 33kV feeders supplying Matraville zone substation as well as Group 3 11kV switchgear can be deferred to be completed by mid 2020s. The estimated cost of this option is $32 million. The NPC is $27 million. Although Option 2 has the lowest NPC, Option 3 is still preferred because: • It provides greater network flexibility than Option 2, as the load transfers required under the latter would leave no spare 11kV panels at Maroubra zone substation; and • There is greater risk due to the magnitude of 11kV cable works required and confidence in the supporting cost estimates. Given the low deferral value available for reducing demand and the scale of load reduction required it was determined that non-network options could not form part of a credible option for this replacement investment.

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The project was approved by Ausgrid Board on 28/03/2017, at a total cost of $15.4 million ($14.2 million excluding contingency). This project is a complex brownfield substation refurbishment, which led to experienced significant delays at development stage.

7.3.1.5 Surry Hills 11kV switchgear replacement Key project milestones: • Project initiated in June 2011. • Project expenditure authorised by Ausgrid Board in February 2015. • Project completion is expected by July 2022. Options Analysis Three network options were considered to address identified issues at Surry Hills ZS: Option 1 – Retire Surry Hills zone substation via 11kV load transfers to surrounding zone substations Campbell St is the only zone substation near Surry Hills with significant spare capacity and potential for expansion; however, even if augmented to its potential three-transformer arrangement it will not have enough spare capacity to absorb the load required to allow full retirement of Surry Hills ZS. Campbell St ZS is forecast to have around 30MVA of spare capacity at the end of the planning period in its augmented arrangement, while Surry Hills ZS load is forecast to be over 55MVA. This option is therefore not considered technically feasible. Option 2 – New Surry Hills zone substation Surry Hills ZS is located in a dense urban area with narrow, busy streets and sensitive residents and businesses. As such, an appropriate site for a replacement zone for Surry Hills would likely be prohibitively expensive. Egress of transmission and distribution cables would likely be difficult, and the cost of transferring load from the old zone to the new zone would likely be more than replacing the switchgear in the existing Surry Hills switch-room. This option would not only resolve issues with the 11kV switchgear, but also resolve condition issues with the 33kV gas pressure cables supplying Surry Hills ZS. The estimated cost of this option is $43 million. The Net Present Cost of this option is $39 million. Option 3 – Replace Surry Hills 11kV switchgear and 33kV feeders In this option, 11kV load is to be transferred from Surry Hills ZS to Campbell St and Camperdown zone substations, allowing staged replacement of the aged 11kV switchgear with fixed-pattern single bus switchgear. The 33kV feeders from Surry Hills STS to Surry Hills ZS would be replaced with modern equivalent technology by 2024. The Net Present Cost of this option is $25 million. Given the low deferral value available for reducing demand and the scale of load reduction required it was determined that non-network options could not form part of a credible option for this replacement investment. Option 2 is significantly more expensive than Option 3, and Option 1 is not technically feasible. As a result, the proposal to replace Surry Hills ZS 11kV switchgear and 33kV feeders (Option 3) is shortlisted as the preferred solution. The project was approved by Ausgrid Board on 25/02/2015, at a total cost of $19.1 million ($18.1 million excluding contingency).

7.3.1.6 Decommission Darlinghurst 33/11kV ZS – Stage 1 Key project milestones: • Project initiated in February 2018 • Project expenditure authorised by the Ausgrid Chief Operating Officer in June 2019 (Stage 1) • Project completion is expected by March 2022 Options Analysis Two network options were considered to address identified asset condition issues at Darlinghurst ZS: Option 1 – Staged retirement by staged transfer of load

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This strategy involves transferring the existing load on Darlinghurst ZS to adjacent zone substations in two stages. The first stage allows for the retirement of the highest risk switchgear with compound insulated busbars, and deferral of the remaining switchgear with air insulated busbars until a later time. The Net Present Cost of this option was $2.8 million (Stage 1 only). Option 2 – Single-staged retirement by transfer of all load This strategy involves transferring all of the existing load on Darlinghurst ZS to adjacent zone substations in one project and allows for the earlier decommissioning of Darlinghurst ZS. There is no cost deferral benefit with this approach. Option 2 was ultimately disregarded because it costs three times more than Option 1 and the fact that replacement of the 11kV air insulated switchgear is not required in the short term. In addition, Option 2 does not provide a corresponding increase in benefits. Given the low deferral value available for reducing demand and the scale of load reduction required it was determined that non-network options could not form part of a credible option for this replacement investment. The project was approved by Ausgrid Chief Operating Officer on 27/06/2019, at a total cost of $4.2 million ($3.9 million excluding contingency). 7.3.1.7 Lidcombe 33/11kV Zone Substation Group 2 11kV Switchgear Replacement Key project milestones: • Project initiated in September 2014. • Project expenditure authorised by Ausgrid Board in December 2017. • Project completion is expected by October 2021. Options Analysis The options analysis was initiated in 2013 and further reviewed in 2014 and 2015. The network options considered solutions to address condition issues with 11kV compound insulated switchgear at Lidcombe ZS and 33kV supply to both Auburn and Lidcombe zone substations. The options explored reconfiguration of the existing zone substations as well as the transition towards a 132kV supply. These options and their corresponding net present costs (NPC) in $ million are listed below:

Option Description NPC

1 Uprate Auburn and retire Lidcombe $68.5M

2 Auburn 132kV conversion and retire Lidcombe (not feasible) N/A

3 Replace both Auburn and Lidcombe with a new 132/11kV zone substation $57.8M

4 Replace 33kV feeders like-for-like and refurbish Lidcombe $72.5M

5 Replace 33kV feeders from Homebush STS to Auburn and reconfigure Lidcombe $58.2M

6 Replace 33kV feeders from Camellia Substation and reconfigure Lidcombe $48.5M

7 Replace Lidcombe with new 132/11kV substation and reconfigure Auburn 33kV feeders $51.9M

8 Replace 33kV feeders from Camellia Substation and reconfigure both substations $42.0M

Given the low deferral value available for reducing demand and the scale of load reduction required it was determined that non-network options could not form part of a credible option for this replacement investment. Option 8 has the lowest NPC and the least risk. It is therefore the preferred option. Further development of this option identified opportunities to defer the replacement of Group 1 switchgear at Lidcombe zone substation, which have been replaced with vacuum trucks. As a result, the scope and cost of the preferred option has been reduced as it considers replacing the 11kV switchgear (Group 2 only) at Lidcombe zone substation now and the remaining switchgroup at a later date. The NPC of the enhanced Option 8 was further reduced to $40.2 million, of which $9.1 million is the contribution of replacing the 11kV compound insulated switchgear (Group 2). This project experienced significant delays because it is developed in combination with the replacement of 33kV feeders supplying Auburn and Lidcombe zone substations. Extensive community consultation on the feeders and coordination issues with the project that involves the widening of the M4 Motorway (part of the WestConnex development) have caused such delays.

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The project was approved by Ausgrid Board on 14/12/2017, at a total cost of $9.1 million ($6.7 million excluding contingency).

7.3.1.8 Decommission Strathfield STS Key project milestones: • Project initiated in August 2015. • Project expenditure authorised by Ausgrid Chief Executive Officer in June 2017. • Project completion is expected by April 2021. Options Analysis Two network options to address the asset condition issues at Strathfield STS were considered: Option 1 – Decommissioning of Strathfield STS This option involves transferring the Sydney Trains Strathfield Substation load from Strathfield STS to Homebush STS by installing two new 33kV feeders. Modifications will need to be made to protection elements and 132kV connections as part of the decommissioning works at Strathfield STS. The transfer of Sydney Trains load will enable the decommissioning of Strathfield STS. 132kV feeders 923 and 924 would need to be modified at the Strathfield STS point along the feeder to become a transition point so that load continues to pass from Mason Park STSS to Burwood zone substation. The cost of this option is approximately $11 million. Option 2 – Refurbishment of Strathfield STS This option involves the like for like replacement of six 33kV circuit breakers and four 132kV isolators at Strathfield STS. In the initial analysis, it was assumed that other secondary issues could be addressed by various replacement sub-programmes at minimal costs. However; additional condition issues have been identified at Strathfield STS and it was discovered that such issues could not be easily addressed via like for like replacement. A refurbishment of the STS would be a complex task that will require extensive staging, since there is limited space available at the Strathfield STS site. This option is estimated to cost in excess of $20 million. Given the low deferral value available for reducing demand and the scale of load reduction required it was determined that non-network options could not form part of a credible option for this replacement investment. Option 1 is preferred because it has the lowest cost and can be delivered in a shorter timeframe than the refurbishment option. The project was approved by the Chief Executive Officer on 21/06/2017, at a total cost of $10.5 million ($9.3 million excluding contingency).

7.3.1.9 New Summer Hill 33/11kV ZS and decommission Dulwich Hill 33/11kV ZS Key project milestones: • Project initiated in March 2012. • Project expenditure authorised by Ausgrid Board in May 2017. • Project completion is expected by February 2021. Options Analysis Three strategies were considered to address issues in the Canterbury Bankstown network area. Each strategy integrates solutions to issues at Enfield, Campsie and Dulwich Hill zone substations. Strategy 1 – Enfield 132/11kV zone substation and Dulwich Hill 33/11kV replacement This strategy involves replacement of the existing 33/11kV Enfield with a new Strathfield South 132/11kV ZS, establishment of a new 33/11kV Dulwich Hill ZS adjacent to the existing zone site and load transfers from Campsie to Enfield to facilitate the switchgear replacement at Campsie ZS. The Net Present Cost (NPC) of this strategy is $62.2 million. Strategy 2 – Replace Enfield and Dulwich Hill zone with new Ashbury 132/11kV zone This strategy involves construction of a new Ashbury 132/11kV ZS and decommissioning of 33/11kV Enfield ZS and Dulwich Hill ZS by transferring all existing load to the new Ashbury ZS. This would be followed by the

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installation of an additional 132/11kV transformer at Ashbury ZS and load transfers from Campsie ZS to Ashbury to facilitate the switchgear replacement at Campsie ZS. The NPC of this strategy is $61.0 million. Strategy 3 – Dulwich Hill and Enfield zone substation replacement This strategy involves 11kV switchgear and 33kV feeder replacement at Dulwich Hill and Enfield ZS’s, with the installation of an additional transformer at Canterbury STS. Another transformer would then be installed at Enfield ZS and load transferred from Campsie to Enfield to facilitate the switchgear replacement at Campsie ZS. The NPC of this Strategy is $80.1 million. Given the low deferral value available for reducing demand and the scale of load reduction required it was determined that non-network options could not form part of a credible option for this replacement investment. Ausgrid’s preferred strategy for Canterbury Bankstown area is Strategy 1, which involves replacing Dulwich Hill Zone substation with a new 33/11kV zone substation. This strategy is preferred because: • Strategies 1 and 2 have NPC estimates that are considered equivalent (within the level of accuracy of the estimate) and materially lower costs than Strategy 3. • Considering the location and characteristics of loads in the area, extensive 11kV work would be required to connect all 11kV feeders to the single point of supply proposed under Strategy 2. 11kV development costs often vary greatly as a result of issues encountered during the construction phase compared to pre-project estimates. Hence, there is less uncertainty in cost estimates for Strategy 1. • Strategy 1 provides greater system flexibility and better coverage of the surrounding 11kV networks than Strategy 2, especially for some load areas (e.g. Belfield, Strathfield and Strathfield South). Additional investigations were carried out to determine the viability of a conversion to 132kV operation, as well as the most ideal location of the new Dulwich Hill ZS. The conversion of Dulwich Hill to 132kV operation was rejected due to the high costs associated with achieving 132kV feeder connections. Although 132kV supply in the area is currently available via feeders 92C, 92X, 91X or 91Y, all these fluid filled cables are targeted for retirement within the next 10 years. Any other 132kV supply to connect a new 132/11kV zone substation at this location would need to originate from Chullora STS (approximately 7km long), looping into the existing 132kV overhead feeders 910/911 via an underground connection (approximately 3km long), or an underground connection from Marrickville zone substation (approximately 4km long). In all these cases, the installation of 132kV switchgear at the Dulwich Hill end will be required. The area to the south of the existing site is the preferred location as it provides one street frontage for 33kV cable replacement and two street frontages for 11kV feeder cutover. In addition, it reduces community impact as works will not be adjacent to residential properties. An aerial view of Dulwich Hill ZS and its proposed replacement is included in the figure below. Existing and proposed substation sites for Dulwich Hill and Summer Hill ZS’s

The project was approved by Ausgrid Board on 01/05/2017, at a total cost of $43.9 million ($40.9 million excluding contingency). A prolonged development time was experienced as the scope of the project was refined to reduce project costs.

7.3.1.10 Rozelle STS new 33kV busbar Key project milestones: • Project initiated in September 2017

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• Project expenditure authorised by Ausgrid Board at a meeting in March 2019 • Project completion is expected by March 2022 Options Analysis Sydney Motorway Corporation has submitted a connection request for a supply of 38MVA for the Main Tunnel (Stage 3A) and 33MVA for the Rozelle Interchange (Stage 3B) of the proposed WestConnex motorway. WestConnex Stages 3A and 3B are both currently under construction. Westconnex Stage 3A is to be supplied from Alexandria 132/33kV STS. Two network options were considered to supply Westconnex Stage 3B: Option 1 – Upgrade Rozelle STS This option includes the installation of a 33kV busbar and upgrade of one Rozelle transformer from 30MVA to 60MVA. This approach provides a diversity of supply to the Westconnex Stage 3 tunnel and will facilitate other future connections at Rozelle anticipated due to development in the Rozelle and White Bay areas. This option provides network assets close to the required connection point. The Net Present Cost of this option is $25.7 million. Option 2 – Expand Alexandria STS Alexandria STS has been recently completed, and would require expansion to facilitate the additional connections. This approach would have all Westconnex Stage 3 tunnel supplies from a common source, does not address other anticipated connection requirements at Rozelle 132/33kV STS. The length of new 33kV cables would be greater with this option. Option 2 was ultimately disregarded because the connection of additional 33kV cables may require complex civil works (i.e. underbore) due to cable access/egress issues in the underground routes at Alexandria STS. In addition, this option will not avoid the need to augment the network to accommodate future load requirements in the Rozelle area. Ausgrid has also considered the ability of non-network solutions to assist in meeting the identified need. A demand management assessment has determined that non-network options cannot cost-effectively address the need to connect the customer loads.

The project was approved by Ausgrid Board on 15/03/2019, at a total cost of $24.2 million ($22.7 million excluding contingency).

7.3.1.11 Replace 33kV feeders – Homebush to Lidcombe ZS and Auburn ZS Key project milestones: • Project initiated in August 2014 • Project expenditure authorised by Ausgrid Board at a meeting in February 2018 • Project completion is expected by July 2023 Options Analysis Auburn and Lidcombe ZS’s are 33/11kV zone substations located in the Inner West area of Ausgrid’s network. These substations are supplied by three 33kV underground feeders respectively, all of which originate at Homebush STS. The oldest sections supplying Auburn ZS date back to 1942, while most feeder sections on the other feeders were commissioned in the 1940s and 1950s. These underground subtransmission feeders are a combination of paper insulated and gas pressure cable technologies, and have reached the end of their service lives. They have a combined length of approximately 37km, from which 22km are paper insulated and the remaining 15km are gas pressure cables. In particular, the gas pressure cables are prone to gas leakages that results in high levels of unavailability due the long time required to locate and repair leaks. While paper insulated cables do not have the same requirements of pressured gas (nitrogen) to maintain insulation integrity and therefore do not present same risks as gas pressure cables, the paper insulated cable sections have experienced a number of outages in recent years. If these issues are left unaddressed, the risk of failure and poor availability of these assets will expose customers in the Inner West network area to a network risk that exceeds allowable levels under the applicable reliability standards. Refer to section 7.3.1.11 for details of the options considered to address identified issues. Ausgrid, working with Endeavour Energy, identified a preferred solution that makes use of spare capacity on the Endeavour network following closure of a Shell Australia oil refinery at Clyde in Western Sydney. Ausgrid considers that these joint planning efforts identified the most efficient solution across the respective networks

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as a whole. In particular, this solution was found to come at a significantly lower cost than rebuilding the existing feeders on a ‘like-for-like’ basis. In fact, the proposed solution defers upstream investments that would otherwise be required if supply of Auburn and Lidcombe ZS’s were to continue to come from Homebush STS. The proposed route from Camellia STS to Auburn ZS is mainly through industrial areas, crossing Duck Creek and the existing M4 Western Motorway by following the Duck River Cycleway. Ausgrid plans to use underground cables in certain areas in response to community feedback and to minimise risks along the M4 motorway. The overhead route between Auburn ZS and Lidcombe ZS will pass primarily through industrial areas and cross under the main western rail line at Percy Street. Ausgrid plans to locate the cables on the western side of Percy Street, on existing low voltage powerline structures to minimise construction impacts. The project was approved by Ausgrid Board on 03/02/2018, at a total cost of $37.2 million ($31.3 million excluding contingency).

7.3.1.12 Willoughby to Mosman 132kV Feeders Replacement Key project milestones: • Project initiated in July 2017. • Project expenditure authorised by Ausgrid Board in October 2018. • Project completion is expected by February 2021.

Options Analysis The 132kV self-contained fluid filled underground feeders supplying Mosman zone substation 9Y7/2, 9Y9/2 from Castle Cove zone substation to Mosman zone substation and 9P7 from Willoughby subtransmission substation to Mosman zone substation are an obsolete technology. These feeders require specialist skills to repair and maintain, outage times can be lengthy, and spares are not readily available. Two options have been considered to address issues with 132kV feeders 9Y7/2, 9Y9/2 and 9P7: Option 1 – Replacement of feeders 9Y7/2 and 9Y9/2 from Willoughby subtransmission substation to Mosman zone substation via future Cremorne Junction zone substation and decommissioning of feeder 9P7 This option involves the installation of two new 132kV feeders from Willoughby subtransmission substation to Mosman zone substation via Ausgrid’s proposed future Cremorne Junction zone substation site. The Net Present Cost of this option is $29.0 million. Option 2 – Replacement of feeders 9Y7/2 and 9Y9/2 from Castle Cove zone substation to Mosman zone substation (like-for-like) and decommissioning of feeder 9P7 This option involves the like-for-like replacement of 132kV feeders 9Y7/2 and 9Y9/2 by installing two new 132kV feeders from Castle Cove zone substation to Mosman zone substation. Feeder 9P7 is to be decommissioned. This option consists of a longer feeder route than Option 1, as well as require new 132kV feeder to connect the proposed Cremorne Junction zone substation. In addition, this option does not provide any reliability improvements, as a loss of Willoughby to Castle Cove feeders 9Y7/1 and 9Y9/1 would result in an outage of both Castle Cove and Mosman zone substations. The Net Present Cost of this option is $37.6 million. The preferred option is Option 1 as it is the highest net market benefit. In addition, this option allows for future expansion through Cremorne Junction zone substation, while requiring a shorter route in comparison to Option 2. A RIT-D was completed for this project in 2018. The project was approved by Ausgrid Board on 29/10/2018, at a total cost of $37.7 million ($35.4 million excluding contingency). The figure bellow provides a geographical view of the Lower North Shore area and highlights the connections between Castle Cove and Mosman and the connection between Willoughby STS and Mosman ZS.

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Lower North Shore network area

7.3.1.13 Waratah 132/33kV STS refurbishment Key project milestones: • Project initiated in April 2010. • Project expenditure authorised by Ausgrid Board in March 2016. • Project completion is expected by June 2022. Options Analysis The 33kV industrial busbar at Waratah STS is significantly aged and needs to be retired from service. The 33kV domestic busbar was refurbished in the 1980s but the oil circuit breakers now require replacement. Four out of seven of the 132/33kV transformers are at the end of their service lives. Two options have been considered to address issues with Waratah STS: Option 1 – Waratah STS supply rearrangement and refurbishment This option involves removing all loads, except major customers, from the Waratah domestic busbar. All unused equipment at Waratah STS is to be decommissioned, including four transformers and three sections of 33kV busbars. In addition, neighbouring zone substations Mayfield, Shortland and Wallsend and Kooragang West switching station are to be decommissioned with all loads to be transferred to new substations recently commissioned or about to be commissioned. The estimated cost for this option is $19.8 million. Option 2 – Waratah STS replacement This option proposes constructing a new 132/33kV substation on a nearby site and decommissioning the existing Waratah subtransmission substation. In addition, neighbouring zone substations Mayfield, Shortland and Wallsend and Kooragang West switching station are to be decommissioned with all load is to be transferred to new substations recently commissioned or about to be commissioned. The estimated cost for this option is $44.3 million. Given the low deferral value available for reducing demand and the scale of load reduction required it was determined that non-network options could not form part of a credible option for this replacement investment. The preferred option is Option 1 as it is the least cost option.

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The project was approved by Ausgrid Board on 30/03/2016, at a total cost of $18.1 million ($ 17.0 million excluding contingency).

7.3.1.14 Peakhurst STS 33kV switchgear replacement Key project milestones: • Project initiated in November 2016 • Project expenditure authorised by Ausgrid Board at a meeting in December 2018 • Project completion is expected by June 2022 Options Analysis Two network options were considered to address the asset condition issues with the 33kV switchgear and switch building at Peakhurst STS: Swap options as per DPAR RIT-D paper Option 1 – Replacement of 33kV switchgear in new building This option involves construction and equipping of a new 33kV switch building within the existing STS site. The Net Present Cost of this option is $26.5 million (with 10% risk). Option 2 – Replacement of 33kV switchgear in existing building This option involves a staged replacement of the 33kV switchgear in the existing switch building, in conjunction with the refurbishment of the building which has structural and roofing problems. The Net Present Cost of this option is $26.6 million (with 40% risk). Option 1 is the preferred option. The estimated costs of each option are similar, however, the cost estimate for Option 2 has much more uncertainty due to the risks and unknowns associated with working in a “brownfield” situation, working around existing live equipment. Option 2 also has increased complexity in staging and longer outage requirements with increase risk of interruptions to customers. A demand management assessment into reducing the risk of unserved energy from the 33kV feeders showed that non-network alternatives cannot cost-effectively address the risk, compared to the two network options outlined above. The project was approved by Ausgrid Board on 17/12/2018, at a total cost of $26.8 million ($25.0 million excluding contingency).

7.3.1.15 11kV Load Transfers from Dalley St ZS to City North ZS Key project milestones: • Project initiated in January 2016. • Project expenditure authorised by Ausgrid Chief Executive Officer in April 2017 (Stage 1) and January 2018 (Stage 2). • Project completion is expected by June 2021. Options Analysis Ausgrid’s strategic decisions for ensuring reliable supply in the Sydney CBD area arise from the need to address ageing infrastructure at City East and Dalley St ZS’s. Three strategies were considered, which will address the identified risks to an appropriate degree: Strategy 1 – New 132/11kV zone substation and decommission Dalley St and City East substations This strategy involves establishing a new 132/11kV substation on the northern section of Sydney CBD, transferring all load at Dalley St and City East to the new zone substation and after that decommission both Dalley St and City East ZS’s. The net present cost of this strategy is $165 million. Strategy 2 – Decommission Dalley St and City East by transferring load to City North and Belmore Park substations This strategy involves transferring approximately two thirds of the existing Dalley St ZS load to City North ZS, and all load at City East as well as the remaining load at Dalley St to Belmore Park ZS. Once completed, both Dalley St and City East substations will be decommissioned. The net present cost of this strategy is $58 million. Strategy 3 – Refurbish existing City East ZS and decommission Dalley St ZS

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This strategy involves transferring City East load to Belmore Park ZS, refurbish City East ZS at 33kV, transferring Dalley St load to the newly refurbished City East and decommission Dalley St ZS. The net present cost of this strategy is $115 million. Strategy 2 has the lowest net present cost and is the preferred option. To capture any differences in the value of the assets remaining at the end of the planning period residual benefits were calculated for each strategy. The present value of residual benefits for Strategies 1 and 3 were $20 million compared to $10 million for Strategy 2. This difference is not material compared to the cost difference of the strategies. As the risk of equipment failure is significant at Dalley St ZS and could result in a prolonged outage, the partial offloading of Dalley St to City North zone substation should be completed as soon as practical. Up to 65% of the load at Dalley St ZS can be transferred to City North ZS, which will substantially reduce network risks at Dalley St and enable relatively low cost recovery actions in the event of a switchgear failure. Non-network options were considered based upon a one-year deferral value of $25/KVA and a total reduction of 50MVA required to be removed from Dalley St zone substation (65% of the load). Given the low deferral value available for reducing demand and the scale of load reduction required it was determined that non-network options could not form part of a credible option for this replacement investment. The 11kV load transfers from Dalley St to City North ZS were initiated as a single project in January 2016. In order to reduce the impacts derived from the construction of the CBD & South East Light Rail Project, the 11kV load transfers were segmented in two stages. The two stages were presented as one project to Ausgrid Board for preliminary project approval (Gate 2 approval) because both are required to address the identified network need. The Board provided Gate 2 approval for the project in April 2016. Stage 1 was authorised by the Chief Executive Officer on 07/04/2017 at a cost of $9.9 million ($9.0 million excluding contingency). The latest schedule review has adjusted the completion date of the project to March 2019. Stage 2 was authorised by the Chief Executive Officer on 03/01/2018, at a total cost of $12 million ($9.9 million excluding contingency). Stage 2 was originally scheduled for completion in September 2018. This second set of load transfers have significant dependencies on the completion of the Light Rail Project, which is experiencing construction delays.

7.3.1.16 Ensuring reliable supply for the Sydney Airport network area Key project milestones: • Project initiated in June 2019. • Project expenditure authorised by Ausgrid Chief Executive Officer in September 2020. • Project completion is expected by January 2024. Options Analysis The 33kV switchgear at Sydney Airport is compound insulated with oil-filled circuit breakers, which could lead to failures ranging from single equipment failures to multiple equipment failures impacting the operation of an entire substation. Furthermore, the 33kV oil circuit breakers at Sydney Airport ZS were originally commissioned in 1955 and are now an orphan technology with very limited spare parts availability. Replacement of the 33kV switchgear in a new switchroom has been identified as the only option available to adress reliability risks based on the outcome of a RIT-D. Condition issues identified in the switchroom buildings have led to the decision to construct a new 33kV switchroom building at the customer’s cost to house the new equipment. The refurbishment of the 33kV switchgear with new equipment in situ (i.e. ‘brownfield replacement’) was also considered under a staged approach. However, brownfield replacement imposes materially greater safety and schedule risk, arising from work being carried out next to energised equipment. Ausgrid also considered other options such as the retirement of the 33kV switchgear or the construction of a new 132/11kV zone substation, but these options were not progressed since they were found technically or commercially not credible. In the case of simple retirement, the reliability of supply would be significantly reduced and future developments in Sydney Airport would be limited. In the case of the new substation, the cost would be materially higher than replacing the switchgear, without providing a commensurate increase in benefits. The scope of this project includes the construction of a new building, installation of new equipment and retirement of the existing 33kV switchgear at Sydney Aiport ZS. Demolition of the existing building and site remediation will also occur as a result of the project. The new switchroom design will also support improved fire segregation, contributing to improved safety and reliability.

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The project was approved by the Ausgrid Chief Executive Officer on 30/09/2020, at a total cost of $9.6 million ($8.6 million excluding contingency).

7.3.1.17 Stockton ZS 11kV switchgear replacement Key project milestones: • Project initiated in November 2018. • Project expenditure authorised by Ausgrid Chief Executive Officer at a meeting dated March 2020. • Project completion is expected by July 2021. Options Analysis The 11kV switchgear at Stockton ZS is compound insulated switchgear and is considered to be beyond its design life. These assets are likely to become less reliable, which could expose customers in the Stockton peninsula to a supply risk that exceeds allowable levels under the applicable reliability standards. One credible network option has been identified to address asset condition issues. It involves the replacement of the 11kV switchgear at Stockton ZS, by constructing and equipping a new switchroom on adjacent land to the existing substation. Other options were considered in the assessment but not progressed. The replacement of the 11kV switchgear in situ involved increased construction risks and longer delivery timeframes relative to the new switchroom. The retirement of Stockton ZS via 11kV load transfers is considered not feasible as the only adjacent substation is Williamstown ZS which is over 10km away. Retiring the substation would therefore require extensive 11kV augmentation and the resulting cost will be signaficantly higher than the replacement of the 11kV switchgear in situ. Another option considered was the construction of a new 33/11kV Zone Substation on a greenfield site to replace the existing Stockton 33/11kV ZS, but it was disregarded because it cost almost three time more than the replacement of the 11kV switchgear in situ and would not provide any additional benefits. Ausgrid has considered the ability of any non-network options to assist in addressing the risks. A demand management assessment examined the possibility of deferring the proposed network investment at Stockton ZS by either 1, 2 or 3 years. The results indicate that costs for non-network alternatives would be considerably higher than the costs of network options. The replacement of the 11kV switchgear with a new switchroom is therefore the preferred option. It involves the installation of a new Mobile Equipment Room to accommodate the new 11kV switchboard comprising two sections of single bus switchgear and 11kV circuit breakers. The project was approved by the Ausgrid Chief Executive Officer on 11/06/2020, at a total cost of $5.7 million ($5.5 million excluding contingency).

7.3.1.18 Muswellbrook ZS Refurbishment Key project milestones: • Project initiated in July 2016. • Project expenditure authorised by Ausgrid Chief Operating Officer at a meeting dated January 2020. • Project completion is expected by December 2021. Options Analysis Condition issues have been identified in the 33kV outdoor switchgear at Muswellbrook ZS. In particular, the 33kV Essantee isolators have additional safety risks to personnel involved in switching operations. Furthermore, the 33kV oil filled circuit breakers of this age and type have a history of failures derived from degraded insulation quality. There are extensive condition issues with the existing control and protection, earthing and oil containment systems. There is also an opportunity to retire/reconfigure parts of the 33kV network after recent projects in the area have resulted in disused 33kV feeders and equipment. One credible network option has been identified to address asset condition issues at Muswellbrook ZS. It involves refurbishing Muswellbrook ZS, to retire the 33kV switchgear that is redundant to the network and replace the minimum equipment to maintain 33kV supply in the area, and rearrangement of the Muswellbrook STS 33kV network. Other options were considered but not progressed because they were not feasible. These included the retirement of Muswellbrook STS and reconfiguration of the 33kV network in the area; the retirement of both Muswellbrook STS and Muswellbrook ZS and transferral of 11kV load to Mitchell Line ZS and Aberdeen ZS, including rearrangement of the 33kV network to provide supply to mine operations and maintain back up supply

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to Moonan ZS and Rouchel ZS; and the establishment of a new Muswellbrook 132/33kV STS. These options were disregarded because the costs were considerably higher, noting that if both Muswellbrook STS and Muswellbrook ZS are retired, the supply capacity will be considerable reduced in the area. The connection of possible future renewable generation will pose increased technical and economic issues without Muswellbrook STS. Furthermore, the reconfiguration of the 132kV network post retirement of Muswellbrook STS will require extensive protection upgrades to achieve compliance with the National Electricity Rules. Ausgrid has considered the ability of any non-network options to assist in addressing the risks. A demand management assessment examined the possibility of deferring the proposed network investment at Stockton ZS by either 1, 2 or 3 years. The results indicate that costs for non-network alternatives would be considerably higher than the costs of network options. Refurbishment of Muswellbrook ZS and rearrangement of the Muswellbrook STS 33kV network is the preferred option. The works will involve the replacement of existing 33kV switchgear and decommissioning existing 33kV switchgear and all redundant 33kV equipment at Muswellbrook ZS, as well as replacement of 33kV feeder and busbar protection. The project was approved by the Ausgrid Chief Operating Officer on 9/01/2020, at a total cost of $3.6 million ($3.3 million excluding contingency).

7.3.1.19 Muswellbrook STS Refurbishment Key project milestones: • Project initiated in July 2016. • Project expenditure authorised by Ausgrid Chief Executive Officer at a meeting dated January 2020. • Project completion is expected by December 2021. Options Analysis Condition issues have been identified in the 33kV outdoor switchgear and secondary systems at Muswellbrook STS. In particular, the 33kV Essantee isolators have additional safety risks to personnel involved in switching operations. Furthermore, the 33kV oil filled circuit breakers of this age and type have a history of failures derived from degraded insulation quality. There are extensive condition issues with the existing control and protection, earthing and oil containment systems. There is also an opportunity to retire/reconfigure parts of the 33kV network after recent projects in the area have resulted in disused 33kV feeders and equipment. One credible network option has been identified to address asset condition issues at Muswellbrook STS. It involves refurbishing Muswellbrook STS, to retire the 33kV switchgear that is redundant to the network and replace the minimum equipment to maintain 33kV supply in the area, and rearrangement of the Muswellbrook STS 33kV network. Other options were considered but not progressed because they were not feasible. These included the retirement of Muswellbrook STS and reconfiguration of the 33kV network in the area; the retirement of both Muswellbrook STS and Muswellbrook ZS and transferral of 11kV load to Mitchell Line ZS and Aberdeen ZS, including rearrangement of the 33kV network to provide supply to mine operations and maintain back up supply to Moonan ZS and Rouchel ZS; and the establishment of a new Muswellbrook 132/33kV STS. These options were disregarded because the costs were considerably higher, noting that if both Muswellbrook STS and Muswellbrook ZS are retired, the supply capacity will be considerable reduced in the area. The connection of possible future renewable generation will pose increased technical and economic issues without Muswellbrook STS. Furthermore, the reconfiguration of the 132kV network post retirement of Muswellbrook STS will require extensive protection upgrades to achieve compliance with the National Electricity Rules. Ausgrid has considered the ability of any non-network options to assist in addressing the risks. A demand management assessment examined the possibility of deferring the proposed network investment at Stockton ZS by either 1, 2 or 3 years. The results indicate that costs for non-network alternatives would be considerably higher than the costs of network options. Refurbishment of Muswellbrook STS and rearrangement of the Muswellbrook STS 33kV network is the preferred option. The works will involve the retirement of a transformer and decommissioning existing 33kV switchgear and all redundant 33kV equipment at Muswellbrook STS, as well as the rearrangement of the 33kV network by dismantling redundant connections and installing new links required. The project was approved by the Ausgrid Chief Executive Officer on 9/01/2020, at a cost of $5.6 million excluding contingency.

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7.3.2 Refurbishment, replacement or augmentations – Dual function Region Committed Refurbishment or Replacement Expected Estimated Investment – Transmission Project Cost ($m) Completion

Carlingford New Macquarie 132/33kV STS Jan-22 34.3

7.3.2.1 New Macquarie 132/33kV STS Key project milestones: • Project initiated in May 2018 • Project expenditure authorised by Ausgrid Board at a meeting in July 2019 • Project completion is expected by January 2022 Options Analysis Three options, including some further variations, have been considered to make provision for the connection of a number of large customers in the Macquarie Park area. Option 1A – New 132/33kV STS on the existing Macquarie Park ZS site, with expansion capability This option was investigated and found not to be viable due to space constraints on the Macquarie ZS site. Option 1B – New 132/33kV STS on a new site, with expansion capability This option was investigated and found not to be viable within the required timeframe (completion 2021). Ausgrid does not own a suitable site and additional land would have to be acquired. Option 1C – New 132/33kV STS on the existing Macquarie Park ZS site, without expansion capability This option was investigated. A number of risks were identified, but it is considered to be viable. This approach is expected to meet the required timeframe of 2021 completion and allows for utilisation of land that is already owned by Ausgrid. The Net Present Cost of this option is $33.7 million. Option 2 – New 132/33kV STS and 132/11kV ZS at Macquarie University, without expansion capability This option was investigated but ultimately not progressed because it is subject to the provision of a suitable site by Macquarie University, and is considered unlikely to meet the required project timeframe. This option was also found to be higher in costs than Option 1C, and involve the construction of new assets remote from the load centre. Option 3 – Third Transformer at Top Ryde ZS, deferring the need for new STS by two years This option would assist in enabling Ausgrid to meet the required customer connection timing, however, it is not efficient as the new 11kV capacity would not be utilized in the longer term. Following a two-year deferral, it is anticipated that one of the other options would still be required. Therefore, this option was disregarded. This would act as an interim measure only and would require a further major network augmentation within a short period of time. The preferred option is Option 1C as it is the only credible option capable to meet the required customer connection timing. The project was approved by Ausgrid Board on 01/07/2019, at a total cost of $40.1 million ($34.3 million excluding contingency).

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Location of proposed new Macquarie STS on existing Macquarie Park ZS site

7.3.3 Committed dual function augmentations There are no identified network constraints requiring dual function asset augmentations at this stage. As no projects have appeared in previous TAPR publications as proposed network augmentations, there cannot be committed projects. For the purposes of the TAPR, an augmentation is considered to be committed if it satisfies all the criteria that are defined in AEMO’s Electricity Statement of Opportunities (SOO), as follows: • Board commitment has been achieved (this requires the appropriate planning approvals and licences to be in place) • Funding has been approved • The project has satisfied the Regulatory Test, and • Construction has either commenced, or a firm date has been set for it to commence

7.4 Urgent and unforseen investments There were no distribution network Regulatory Test projects required to address an urgent or unforeseen network investment in the preceding year. There were no dual function asset RIT-T projects or Regulatory Test projects required to address an urgent or unforeseen network investment in the preceding year.

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8 Joint planning

Joint Planning is carried out with other Network Service providers, in particular TransGrid, Endeavour Energy, Essential Energy and Sydney Trains. 8.1 Joint planning with TransGrid TNSP Ausgrid plans its transmission network jointly with TransGrid as the Ausgrid 132kV dual function network provides support to TransGrid’s 330kV network. In carrying out joint planning TransGrid and Ausgrid: • meet regularly, at least 4 times per year; • record minutes and decisions; • prepare work plans and monitor progress; • assess augmentation options on the basis of least cost to the community; • initiate projects within each organisation following the normal approval processes; and • jointly consider demand management as an option. Ausgrid and TransGrid have established a Joint Planning Committee structure which comprises a steering committee and a joint planning sub-committee to coordinate the planning activities of Ausgrid and TransGrid in accordance with the joint planning requirements of the National Electricity Rules. Under the agreed terms of reference, there are quarterly meetings of the sub-committee and bi-annual steering committee meetings. Members include relevant planning, operations, design and project development staff. The key considerations of the joint planning committees are: • load forecasting; • connection agreement issues, including major new connections; • reliability criteria; • major plant refurbishment; • plant retirement issues; • demand management and embedded generation opportunities; • network augmentation options; • reactive plant requirements; • system fault levels; • earthing coordination; • major network control coordination; • overview of protection, metering and communication issues; and • network business communication requirements. Committee activities and deliverables are managed through an agreed work plan, with decisions documented in approved Joint Planning Reports for major milestones. Joint Planning Report sign-offs range from Planning Manager level (Ausgrid L5) for more routine agreements up to Executive level. The more routine operational decisions and actions required are agreed on and recorded via the joint planning meeting minutes. 8.1.1 Process and methodology Ausgrid plans the Inner Sydney Metropolitan, Central Coast and Lower Hunter Transmission Load Areas jointly with TransGrid. From 1 July 2018, TransGrid and Ausgrid are required to comply with the “NSW Electricity Transmission Reliability and Performance Standard 2017”. This standard requires the NSW electricity transmission network to be designed and planned to a certain level of redundancy and level of expected unserved energy. This is a significant change from the former deterministic assessment of the network. Each bulk supply point is allocated one of three categories. The level of redundancy required for each category is as follows: • Category 1 – a supply interruption may occur following the outage of a single system element;

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• Category 2 – a non-zero amount of load must be supplied following the outage of a single system element; or • Category 3 – a non-zero amount of load must be supplied following the outage of a single system element. In addition, for Inner Sydney, a non-zero amount of load must be supplied following the simultaneous outage of a single 330kV cable and any 132kV feeder or 330/132kV transformer. There is provision in the standard for flexibility in planning for the level of expected unserved energy. Compliance with the expected unserved energy allowance is not required provided that: • A plan regarding measures for altering the reliability of the supply capacity of the bulk supply point has been developed and submitted to IPART; • That the plan provides a greater net-benefit, using the cost-benefit methodology defined in the RIT-T, than the net-benefit of compliance with the standard; and • That IPART has advised in writing that it is satisfied that the plan submitted, if implemented would: • Be likely to provide a greater net-benefit than would be provided with compliance; and • Not result in a material reduction in the level of expected unserved energy at any bulk supply point. The NER sets out the planning process and consultation requirements and includes requirements on forecasting, annual reviews, regulatory tests and consultations. The main inputs to the joint planning process are: • Ausgrid supply point load forecasts; • Review of network capacity and utilisation; • Planning criteria and indicators; • Condition, operational and risk assessments; • TransGrid transmission network and Ausgrid supporting dual function network load flow analysis; and • TransGrid – Ausgrid network planning reviews.

8.1.2 Joint TransGrid - Ausgrid planning completed in 2020 8.1.2.1 Sydney Inner Metropolitan transmission load area Existing and future constraints on the Sydney Inner Metropolitan transmission network are centred on two critical areas: • Transmission supply into Beaconsfield BSP from Bulk Supply Points at the edge of the city, Sydney South, Sydney North, and Rookwood Rd BSP. This is known as Transmission Corridor 1 (‘TC1’). • Transmission supply into Haymarket BSP and surrounding Ausgrid 132kV zone substations from Sydney South BSP (Cable 42) and Ausgrid 132kV connections from Beaconsfield BSP and the meshed 132kV network. This is known as Transmission Corridor 2 (‘TC2’). Both transmission corridors operate as meshed systems of 330kV and 132kV circuits, with significant interdependencies between both corridors. Both have limitations due to the age and condition of existing circuits, including significant reduction in capacity of cables where in-situ conditions are not adequate to support design ratings. The Inner Metropolitan Area Joint Planning strategy must resolve issues on both corridors. During 2014, TransGrid and Ausgrid consulted widely on the Powering Sydney’s Future project, which was jointly formulated to address network needs for assets within transmission corridors TC1 and TC2. At the time, there were five key drivers behind the Powering Sydney’s Future project – namely: • the ‘modified N-2’ NSW transmission reliability standard in place at the time; • the age and reliability of TransGrid’s Cable 41; • the rating of Cable 41, which had been derated from 663 MVA to 575 MVA in 2011; • the rating and retirement of Ausgrid oil-filled cables; and • peak demand was forecast to increase. In 2016, the Powering Sydney’s Future project commenced the formal RIT-T process. Between 2014 and 2016, a number changes to the key drivers occurred, in particular: • all oil-filled cables in Inner Sydney are now two years older and consequently less reliable; • a further derating of Cable 41 from 575 MVA to 426 MVA in August 2016 as a result of testing the thermal resistivity of backfill and bedding materials; and

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• an increase in summer peak demand in Inner Sydney in 2016 and a forecast increase in demand from heightened economic activity expected within Inner Sydney TransGrid and Ausgrid considered a range of options and their ability to address the risk of supply disruption for consumers. Both network and non-network solutions were considered as potential credible options for the RIT-T analysis – in particular: • a range of network options were included in the RIT-T assessment • non-network option components were incorporated into the assessment of all network options to potentially defer the timing of network investment. The preferred strategy for Powering Sydney’s Future to address the network needs was identified as the following: • A combination of non-network solutions to manage the risk of unserved energy before the network option can be commissioned • installing two 330 kV cables in two stages, with commissioning of the first cable in time for the 2022/23 summer • operating 330kV Cable 41 at 132 kV from 2022/23 • decommissioning Ausgrid’s cables in two stages. In April 2018, the Australian Energy Regulator (AER) made it’s final determination of Transgrid’s 2018-2023 regulatory submission, which included the Powering Sydney’s Future project. The final determination included full provision for the first stage of Powering Sydney’s Future as proposed in TransGrid’s revised regulatory submission. With completion of the RIT-T and funding approval, TransGrid and Ausgrid proceeded to develop the first stage of the Powering Sydney’s Future project. The NSW Department of Planning, Industry and Environment (DPIE) approved the first stage of the Powering Sydney’s Future project on 14 May 2020. It followed the public exhibition and submission of the Environmental Impact Statement (EIS) from 11 October to 22 November 2019. Construction began in August 2020 and will continue until late 2022. 8.1.2.2 Sydney Inner Metropolitan transmission load area (greater network) TransGrid’s Sydney East 330/132kV Bulk Supply Point substation was commissioned in 1965. The substation is a major interconnection point in the TransGrid 330kV network and is the sole source of supply to Ausgrid’s substations in Sydney’s Northern Beaches and North Shore areas. One of the 330/132kV transformers at Sydney East Substation was recently replaced but the remaining three transformers are now approaching the end of their serviceable life. Joint planning in 2018 determined that two of the three older Sydney East transformers should be replaced and the third should be retired without replacement. TransGrid completed the RIT-T process to replace these two transformers in June 2019. TransGrid and Ausgrid will review the need for a fourth transformer at Sydney East as part of the normal annual planning process. Work is now underway to replace the two transformers. TransGrid’s Beaconsfield 330/132kV substation originally had three transformers. Transformer number 3 was installed in 2012. Joint planning in 2015 determined that one of the two older Beaconsfield transformers should be replaced and the second should be retired without replacement. These works were completed in 2017. Since then, there has been an increase in the demand forecast and a reduction in capacity of the 330kV cable supplying Beaconsfield. In 2018, a new standard was introduced for Electricity Transmission Reliability and Performance. TransGrid and Ausgrid are currently reviewing the need for a third transformer at Beaconsfield in light of the new transmission reliability standard and the expected implementation of the first stage of Powering Sydney’s Future. As a result of the increase in rooftop photovoltaic (PV) solar installations in the Sydney Northern Beaches and North Shore areas over the past 10 years, the voltage level on the LV network has increased. The continued increase in voltage levels can no longer be managed by transformer taps on the 11kV distribution network and zone substation transformers. Subsequently, a new holistic approach to voltage management has been undertaken determining that upstream voltage levels on the subtransmission network supplied by TransGrid’s Sydney East 330/132kV substation also remained quite high as transformers at subtransmission substations did not have an adequate tapping range to achieve the required voltage levels on the 33kV networks. After implementing easily available options (with minimal expenditure) within the Ausgrid network, the investigation also concluded a reduction to the voltage level at Sydney East 330/132kV substation was also required. TransGrid is currently implementing this reduction in voltage level with completion expected in early 2021. 8.1.2.3 Transmission load area – Central Coast As a result of the increase in rooftop photovoltaic (PV) solar installations in the Central Coast area over the past 10 years, the voltage level on the LV network has increased. The continued increase in voltage levels can no longer be managed by transformer taps on the 11kV distribution network and zone substation transformers. Subsequently, a new holistic approach to voltage management has been undertaken determining that upstream voltage levels on the Central Coast subtransmission network also remained quite high as transformers at subtransmission substations did not have an adequate tapping range to achieve the required voltage levels on

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the 66kV and 33kV networks. After implementing easily available options (with minimal expenditure) within the Ausgrid network, the investigation also concluded a reduction to the voltage level at several Central Coast transmission connection points was also required. TransGrid is currently reviewing the scope of works required to change voltage levels at three BSPs (Tuggerah, Vales Point and Munmorah) and a project will be initiated in 2021. Due diligence studies on the Vales Point 53MW Solar Farm connected to the 33kV network is complete. Ausgrid is preparing to formally submit the Connection Application to AEMO on behalf of the generator proponent. No other significant issues were identified on the Central Coast network. 8.1.2.4 Transmission load area – Lower Hunter TransGrid has successfully implemented voltage level changes at Newcastle, Tomago and Waratah West BSP’s aiding in effective voltage management from transmission connection points to network customers. Ausgrid has received numerous enquiries for large generator connections (generally more than 30MW) in the Lower Hunter area. Ausgrid has also received and addressed an enquiry regarding a large gas fired power station (>250MW) proposed to be installed on the site of the now retired Hydro Aluminium Smelter. No other significant issues were identified in the Lower Hunter transmission network. 8.1.2.5 Voltage Planning TransGird and Ausgrid initiated a voltage specific joint planning stream in 2020. The voltage specific planning stream provides for a BSP to LV customer planning approach for our whole network whilst aligning with the upstream TransGrid voltage requirements. As a result, in 2020 Ausgrid has issued requests to change voltage levels at four BSP’s including Sydney East, Tuggerah, Munmorah and Vales Point. 8.1.3 Planned joint TransGrid-Ausgrid network investments Planned future network investments, excluding committed projects, discussed at TransGrid - Ausgrid joint planning meetings in the preceding year include: • Planning discussions including identified needs reviews and on-going feasibility studies to review and refine a range of supply options for the Inner Sydney Metropolitan transmission load area. This will include approaches to meet any supply shortfall before the commissioning of the first stage of the Powering Sydney’s Future Project. 8.1.4 Additional information Further information on TransGrid and Ausgrid’s completed joint planning and joint network investment can be found in TransGrid’s Transmission Annual Planning Report. It is published on their website as well as AEMO’s website.

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8.2 Joint planning with other DNSPs Ausgrid follows the same principles when joint planning with Endeavour Energy, Essential Energy and Sydney Trains. However due to the limited number of network dependencies between the organisations, joint planning meetings may only take place once per year, or less, unless a particular issue has been identified and needs to be progressed and monitored. 8.2.1 Process and methodology Joint planning meetings with Endeavour Energy and Essential Energy are arranged on a needs basis, and generally there are not more than two meetings in any year. The joint planning process and methodology is similar to the joint planning process between Ausgrid and TransGrid. A formalised joint planning arrangement is also in place with Sydney Trains. Joint planning meetings may be initiated by any party to discuss planning issues, identified network needs and proposed solutions near adjoining network boundaries that are likely to affect either party. The joint planning meetings are also the forum used to discuss proposed changes on the network that may have a material impact on either DNSPs network. 8.2.2 Joint Ausgrid and other DNSP planning completed in preceding year Following the joint planning meeting in October 2019 with Essential Energy, it was agreed to change the frequency of joint planning meetings to every 2 years and therefore there was no joint planning meeting between Ausgrid and Essential Energy this year. Minor enquiries were handled sufficiently through email or phone contact without the need for a joint planning session. Essential Energy will continue to review the demand growth at Clarencetown and Seaham areas, which may result in a requirement to increase the capacity of one 11kV connection supplied by Ausgrid. Ausgrid had no need to carry out joint planning with Endeavour Energy this year. However, there were regular project meetings with Endeavour Energy in relation to the planned supply of Auburn and Lidcombe zone substations from Endeavour Energy’s Camellia Transmission Substation. There are no other identified network issues that affect either Endeavour Energy or Ausgrid. Quarterly planning meetings were held with Sydney Trains, with ongoing regular meetings planned to ensure that the electrical network can cater for increased power requirements of new trains and timetables. 8.2.3 Planned DNSP joint network investments There is currently a project to supply Auburn and Lidcombe zone substations from Endeavour Energy’s Camellia Transmission Substation. There is a project to rectify the 33kV supply to Essential Energy from Ausgrid’s Tanilba Bay zone substation to meet the capacity requirements specified in the connection agreement. A LIDAR review of the 33kV supply identified construction and design issues with the overhead 33kV feeder which increases the risk of network faults and electrical hazards to the public. There were no jointly planned network investments with Sydney Trains in the preceding year. 8.2.4 Additional information Information on completed Ausgrid and other DNSP joint planning and joint network investments may be found in Ausgrid Distribution and Transmission Annual Planning Reports published on our website. Where a proposed future DNSP joint planning project satisfies the requirements for a RIT-D project, the identification of non- network options, the consultation on potential credible options and their economic assessment will be published in accordance with the NER.

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9 Network performance

9.1 Reliability measures and standards Ausgrid’s objective is to maintain reliability performance at current levels and comply with regulatory requirements at minimum cost, given the condition and utilisation of existing network assets and the funding available to maintain and augment the electricity network.

Under the NSW Reliability and Performance (R&P) Licence Conditions for Electricity Distributors12 Ausgrid is required to comply with specific targets for reliability standards and individual feeder standards. The purpose of the licence conditions is to facilitate the delivery of a safe and reliable supply of electricity. Ausgrid is required to report to the Minister to ensure compliance with the R&P licence conditions. Under the National Electricity Rules (NER), and the Service Target Performance Incentive Scheme (STPIS), Ausgrid is given financial incentives to improve the customer’s reliability performance compared to historic outcomes over time (as well as penalties if the performance level deteriorates). Reliability measures used are SAIDI (System Average Interruption Duration Index), or minutes off supply for the average customer, and SAIFI (System Average Interruption Frequency Index), or number of interruptions experienced by the average customer. The reliability performance is monitored at distribution feeder level for unplanned interruptions (excluding major event days, planned interruptions and circumstances beyond the reasonable control of the electricity distributor). The distribution feeders are categorised as CBD (Sydney CBD), Urban, Short Rural and Long Rural based on feeder length and load density. Ausgrid distribution network consists of 59 CBD feeders, 1901 Urban feeders, 383 Short Rural feeders and 5 Long Rural feeders. Almost 83% of Ausgrid’s customers are connected to Urban feeders. Our customers must plan around the possibility that the electricity supply may not always be available and that interruptions could occur without notice, or with notice in accordance with their supply contract. 9.1.1 Supply reliability standards 9.1.1.1 Average feeder category reliability standards The purpose of the R&P licence condition Schedule 2 – “Network Overall Reliability Standards” is to: • define minimum average reliability performance, by feeder type, for a distribution network service provider across its distribution network, and • provide a basis against which a distribution network service provider’s reliability performance can be assessed.

Average Reliability Standards

CBD Urban Short Rural Long Rural SAIDI 45 80 300 700 SAIFI 0.30 1.20 3.20 6.00

12 The Minister for Energy established licence conditions for distribution network service providers on 1 August 2005 (revised December 2007, July 2014,for the Ausgrid Operator Partnership (“Ausgrid”) on 1 December 2016, and for the operator of a transacted business on 4 December 2017. These were further amended in February 2019). See: Annexure B and https://www.ipart.nsw.gov.au/Home/Industries/Energy/Energy-Networks-Safety-Reliability-and-Compliance/Electricity- networks/Licence-Conditions-and-Regulatory-Instruments

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9.1.1.2 Individual feeder standards The purpose of the R&P licence condition Schedule 3 – “Individual Feeder Standards” is to: • specify minimum standards of reliability performance for individual feeders; • require a distribution network service provider to focus continually on improving the reliability of its feeders, and • enable the reliability performance of feeders to be monitored over time.

Individual Feeder Standards

CBD Urban Short Rural Long Rural SAIDI 100 350 1000 1400 SAIFI 1.4 4 8 10

9.1.1.3 Individual customer standards The purpose of the R&P licence condition Schedule 8 – “Individual Customer Standards” is to: • specify minimum standards of reliability performance for individual customers; • require a distribution network service provider to focus continually on improving the reliability of its customers, and • enable the reliability performance of customers to be monitored over time.

Individual Customer Standards

Minutes Interrupted Number of Interruptions Metro 350 4 Non-metro 1000 8

9.1.2 Network Supply reliability performance in the preceding year 9.1.2.1 SAIDI and SAIFI Performance The following graphs depict the normalised (i.e. Major Event Days data excluded) SAIDI and SAIFI trends over the 10-year period 2010/11 to 2019/20 AER normalised SAIDI 120

100 98 92 80 82 77 76 79 75 68 72 69 60

OrganisationalSAIDI 20

Figure 9.1: Global unplanned SAIDI

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AER normalised SAIFI 1.2 1.09 1.0 0.91 0.8 0.83 0.73 0.71 0.68 0.70 0.68 0.66 0.68 0.6

0.4

OrganisationalSAIFI 0.2

0.0

Figure 9.2: Global unplanned SAIFI

9.1.2.2 Major Event Days Ausgrid uses the methodology described in IEEE 1366 standard for defining Major Event Days, as outlined in the R&P licence conditions and AER STPIS Definitions. There were eight Major Event Days for 2019/20.

Date Excluded SAIDI Cause of Major Event Day

26/11/2019 58.79 Storm

20/01/2020 4.93 Storm

23/01/2020 5.97 Storm

8/02/2020 4.25 Storm

9/02/2020 139.43 Storm

10/02/2020 10.02 Storm

18/02/2020 17.74 Storm

19/02/2020 4.25 Storm

9.1.2.3 Individual Feeder Reliability Performance As required under the R&P Licence Conditions for Ausgrid, each feeder currently exceeding the Individual Feeder Standard is analysed and an investigation report identifying the causes and, as appropriate, any action required to improve the poor performance is reported in the next quarterly performance report. The majority of feeder exceedances were determined to be random events and action was limited to monitoring ongoing reliability performance. A small number of feeders required remedial actions such as vegetation management and repairs to network assets or minor capital works. All actions required were completed in the timeframes required. Ausgrid has an ongoing reliability management program that targets those feeders that have exceeded the Individual Feeder Standards as outlined in Schedule 3 of the R&P Licence Conditions. The individual feeder performance against the standard is given in the table below.

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Individual feeder performance against the standard during 2019/20

CBD Urban Short Rural Long Rural

Feeders (Total Number) 59 1,901 383 5 Feeders that Exceeded the Standard 2 89 13 1 during the Year

Feeders Not Immediately Investigated 0 0 0 0

Feeders Not Subject to a Completed 0 0 0 0 investigation report by the Due Date Feeder Not having Identified Operational Actions Completed by 0 0 0 0 Due Date Feeders Not having a Project Plan 0 0 0 0 Completed by Due Date

9.1.2.4 Feeder Categories Reliability Performance All feeder category performances were compliant against the NSW R&P Reliability Standards for 2019/20 except for urban SAIDI that exceeded by 0.96 minutes.

Whole Organisation and Feeder Category reliability performance

12-month period to end of June 2019

Rural Rural ORG* CBD Urban short long

Actual 92.18 3.62 80.96 160.65 652.53 SAIDI Licence Conditions 45 80 300 700 standard Actual 0.68 0.01 0.64 1.01 2.05 SAIFI Licence Conditions 0.30 1.20 3.20 6.00 standard Note: * Refers to the average performance of the organisation overall. This measure does not form part of the licence conditions but is needed to calculate the overall NSW result.

Ausgrid’s FY20 Urban SAIDI result was 80.96 minutes, which marginally exceeded the Ministerially Imposed Licence Condition annual standard of 80 minutes. There were multiple contributing factors, most notably severe weather events, Ausgrid’s live work pause and a consequent increase in defective mains and apparatus.

Improvement initiatives such as live work training, prioritisation of high customer impact HV faults, increased focus on repairing the DMAs, high level of scrutiny on sub-transmission network planned outages combined with return to more normal weather has already reflected flattening of Urban SAIDI. This provides confidence that urban SAIDI levels will be comfortably below the Urban SAIDI threshold in FY21.

9.1.2.5 Individual Customer Standards Performance As required under the R&P Licence Conditions for Ausgrid, customers currently exceeding the Individual Customer Standard is analysed and an investigation report identifying the causes and, as appropriate, any action required to improve the poor performance is reported in the next quarterly performance report. The individual customer performance against the standard is given in the table below.

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Individual Customer performance against the standard during 2019/20

Metro Non Metro Customers that Exceeded the 1 0 Standard during the Year Customers Not having a Project 0 0 Plan Completed by Due Date

We have issued a project to improve the reliability of the customer via the installation of field reclosers on the feeder, with a forecast due date completion date of late 2020.

9.1.3 Service Target Performance Incentive Scheme (STPIS) The Australian Energy Regulator's (AER) distribution Service Target Performance Incentive Scheme (STPIS) provides a financial incentive for Ausgrid to maintain or improve its reliability and customer service performance over time. As part of the AER final determination for Ausgrid, the AER set elements of the STPIS for the 2019/20 – 2023/24 period including at-risk revenue caps, reliability targets, and customer service targets. The revenue at risk for each regulatory year is capped at 5 per cent with a 4.5 per cent cap for the reliability of supply component and 0.5 per cent cap for the customer service component. The SAIDI and SAIFI targets set by the AER in their final determination for each feeder category for the reliability component of the STPIS are set out in the tables below13.

STPIS results – Unplanned SAIDI Targets vs Actuals 2018/19 2019/20 Target Actual Target Actual CBD 16.58 24.68 9.09 3.62 Urban 62.41 65.84 59.91 80.96 Short Rural 157.28 131.71 127.96 160.65 Long Rural 436.53 465.90 496.12 652.63

STPIS results – Unplanned SAIFI Targets vs Actuals 2018/19 2019/20 Target Actual Target Actual CBD 0.054 0.11 0.038 0.01 Urban 0.674 0.60 0.603 0.64 Short Rural 1.426 1.04 1.139 1.01 Long Rural 3.099 2.22 2.481 2.05

9.1.4 Forecast of network reliability performance Ausgrid’s Reliability Forecasting System (RFS) forecasts the reliability performance of each feeder category based on 5 years of historical performance.

13 Table extracted from the AER’s Final Decision Ausgrid Determination 2019-24 Attachment 10 Table10.2 – Service Target Performance Incentive Scheme.

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SAIDI 2020/21

System 78 CBD 13 Urban 70 Short Rural 131 Long Rural 579 (Average minutes of supply interruption per customer per year)

SAIFI 2020/21

System 0.69 CBD 0.05 Urban 0.63 Short Rural 1.07 Long Rural 2.58 (Average number of network interruptions per customer per year)

Where a shortfall in reliability is identified for feeder category performance, improvement methods may include: • improvements of individual feeder performance - affecting a sufficient number of individual feeders to influence the category average, or • Improvements at a subtransmission level, or • Improvements with wide spread impacts such as operating policy and its implementation, SCADA systems, and the development of intelligent network options. Project proposals within these three categories are short-listed and the anticipated cost benefit of each option is estimated. The cost estimates are based on standard unit costs and adjusted to reflect, to the extent practicable, the realities of implementing the solution. 9.1.5 Compliance with network reliability standards Ausgrid monitors feeder outages and records the duration of outage events into the Outage Management System (OMS). For reliability reporting purposes, the network performance is measured at the distribution feeder level. Excluding any excluded events, including planned interruptions and Major Event Days, the recorded outage information provides Ausgrid with the frequency and duration of feeder outages that are used to determine the SAIDI and SAIFI of individual feeders. In turn these individual feeders are grouped into categories, to enable an average SAIDI and SAIFI to be determined for each feeder category (CBD, Urban, Short Rural and Long Rural). Every quarter Ausgrid submits a report stating the business performance against the overall Reliability, Individual Feeder and Customer Service Standards to IPART and the Minister administering the Electricity Supply Act 1995 within one month of the end of each quarter. The report lists performance against the pro-rata SAIDI and SAIFI average standards, along with any reasons for non-compliance and Ausgrid’s plans to improve the feeder performance. Similarly, the Individual Feeder document details the date at which a feeder first exceeded the relevant Individual feeder standard and the SAIDI and SAIFI performance for that 12 month period, including details of the remedial action to be taken to improve performance, and the planned date of completion for the action plan. Typical remedial action plans include either operational and/or capital expenditure, or alternatively there is the option of a non-network solution. Operational work may include works like vegetation maintenance or retro-fitting of animal proofing on electrical mains and apparatus. Any identified and reported operational work is due to be completed by the end of the third quarter following the feeder first exceeding the individual feeder standards. Capital expenditure to improve feeder reliability can be in the form of a network augmentation project involving feeder reclosers or covered overhead mains to prevent or correct some known outage triggers. Any required capital work is to be developed, planned and commenced by the end of the second quarter following the feeder first exceeding the individual feeder standards. Some investigations find that a feeder outage occurred due to a one-off event that is not likely to occur again.

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Non-network solutions may include energy storage systems to provide ride-through capability during outages. . 9.2 Quality of supply standards Ausgrid’s objective is to achieve the best possible overall supply quality of our electricity network, given the condition and utilisation of existing network assets, within the funding available to maintain and augment the electricity network. The NSW Code of Practice - Electricity Service Standards14 provides a framework for supplying electricity to customers on the Distribution Network. Ausgrid’s network standard NS 238 Supply Quality15 sets out Ausgrid’s standards for Quality of Supply which customers can expect from Ausgrid’s network. Ausgrid does not control the frequency on the electricity supplied through its electricity network, as this standard is set during the electricity generation process. The Australian Energy Market Operator (AEMO) establishes standards and regulates the frequency of supply on the national grid. 9.2.1 Voltage range for supplied electricity Supply voltage is the voltage, from phase to neutral or phase to phase, for electricity that is supplied at a customer’s point of supply. Maintaining this steady state supply voltage is important to ensure appropriately designed equipment does not malfunction and is not damaged. When Ausgrid identifies or is notified that the steady state supply voltage is outside the specified target range, Ausgrid will take reasonable steps to modify the network to ensure that the voltage will be maintained at the required level and achieve Ausgrid’s steady state voltage supply objective. 9.2.1.1 Low voltage network Ausgrid’s objective for the operation of its network is to maintain a target steady state phase to neutral supply voltage (measured as a ten-minute average) within the range of 216V to 253V at customers’ points of supply under normal operating conditions. This range is the nominal voltage range of 230V as defined in the relevant Australian Standard AS 61000.3.100, with a tolerance of +10%/- 6% to allow for voltage regulation on the mains th between distribution substations and customers’ points of supply. The 99 percentile (V99%) of the 10 minute st average voltage readings for a 1 week survey should be less than 253V and the 1 percentile (V1%) should be greater than 216V. 9.2.1.2 High voltage network Ausgrid’s high voltage distribution network operates at several voltage ranges. Accordingly, high voltage customers must obtain from Ausgrid the network operating objective for supply voltage applicable to their location, particularly before proceeding with any project expenditure or commitments. 9.2.1.3 Applicable quality of supply codes, standards and guidelines Ausgrid relies on the following standards and/or guidelines when setting and assessing network voltage performance: • Network Standard: NS 238 Supply Quality • Australian Standards: AS/NZS 60038 and AS 61000.3.100 • NER S5.1a.4 – Power Frequency Voltage • NSW Service and Installation Rules (SIR): Section 1.10.1 refers to AS/NZS 600038 & AS 61000.3.100. 9.2.2 Harmonics and total harmonic distortion Voltage waveform distortion including harmonic distortion results from the operation of appliances or equipment that draw non-sinusoidal currents from the network. Harmonic distortion can cause the supply voltage to depart from a sine wave in a repetitive manner. Maintaining waveform distortion within acceptable limits is important because it can otherwise cause interference and damage to sensitive customer and network equipment. This form of distortion can also cause light flicker, incorrect operation of ripple control devices (used for off peak electric hot water) and computers, audible noise in television, radio and audio equipment and vibration in induction motors. 9.2.2.1 Applicable quality of supply codes, standards and guidelines Ausgrid relies on the following standards and/or guidelines when limiting and assessing harmonic performance:

14https://web.archive.org/web/20180319221006/https://www.resourcesandenergy.nsw.gov.au/energy-supply-industry/pipelines-electricity- gas-networks/network-connections/electricity_connect_code_of_practice_electricity_service_standards.pdf

15https://www.ausgrid.com.au/-/media/Documents/Technical-Documentation/NS/ns238.pdf

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• Network Standard: NS 238 Supply Quality • Australian Standards: TR IEC 61000.3.6:2012, AS 61000.2.2:2003, AS 61000.2.12:2003, SA/SNZ TR IEC 61000.3.14:2013 • Standards Australia handbook for power quality HB264 • NER S5.1a.6 – Voltage Waveform Distortion • NSW Service and Installation Rules (SIR): Section 1.16.2.1 (b) refers to AS/NZS 61000.3.2, 61000.3.4, 61000.3.12. 9.2.3 Voltage fluctuations (Flicker) – Applicable quality of supply codes, standards and guidelines Ausgrid relies on the following standards and/or guidelines when limiting and assessing Voltage fluctuations performance: • Network Standard: NS 238 Supply Quality • Australian Standards: TR IEC 61000.3.7:2012, AS 61000.2.2:2003, AS 61000.2.12:2003, SA/SNZ TR IEC 61000.3.14:2013 • NER S5.1a.5 – Voltage Fluctuations • NSW Service and Installation Rules (SIR): Section 1.16.2.1 (b) refers to AS/NZS 61000.3.3, 61000.3.5, 61000.3.11. 9.2.4 Voltage unbalance – Applicable quality of supply codes, standards and guidelines Ausgrid relies on the following standards and/or guidelines when limiting and assessing Voltage Unbalance performance: • Network Standard: NS 238 Supply Quality • Australian Standards: TR IEC 61000.3.13:2012, AS 61000.2.2, AS 61000.2.12, SA/SNZ TR IEC 61000.3.14:2013 • NER S5.1a.7 – Voltage Unbalance. 9.3 Quality of supply performance for preceding year At Ausgrid, monitoring for supply quality is undertaken by a number of means including review of customer complaints files, permanent monitoring at a selection of sites across the network at different voltage levels, undertaking survey of distribution substation voltages, installation of temporary meters at customer premises to investigate supply quality complaints, and participation in the Long Term National Power Quality Survey (LTNPQS) conducted by the University of Wollongong. 9.3.1 Supply voltage performance Voltage is measured to AS 61000.3.100.

Distribution substations with Voltage monitoring showed 100% of sites met the V1% limit and 95% of sites met the V99% limit The 5% of sites not meeting the V99% figure is a consequence of the network being historically designed for a nominal 240V range. As stated in the next section 9.4 (Corrective Action) Ausgrid has an ongoing reactive program to lower network voltages towards the nominal 230V standard as issues are identified on the network. In recent years, the high penetration of solar generation has resulted in localised high voltage issues generally observed by customers experiencing loss of energy exports due to inverter behaviour as prescribed under AS/NZS 4777. 112 complaints were received regarding Solar Inverter interruptions from High Grid Voltage. In the majority of cases these were resolved by either changing the Power Quality response modes of the customer’s inverter(s) as specified in AS/NZS 4777 or by way of ‘tap changes’ on the customer’s supplying transformer. 9.3.2 Harmonic content of supply voltage waveform There were no complaints registered for harmonic issues. 9.3.3 Voltage fluctuations (Flicker) performance There were 26 complaints registered as being about flicker or fluctuations. One was confirmed to be flicker or fluctuations within the definition of TR IEC 61000.3.7 standard. The site in question was supplied from a Zone Substation that has the same high Voltage supply that connects to an Electric Arc Furnace. Of the remaining 25 complaints: • 7 were identified as no fault found or other network cause.

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• 18 were related to light flicker caused by Ripple Control signals on the network. 9.3.4 Voltage unbalance performance There were no complaints registered as being Voltage unbalance. 9.4 Corrective action planned to meet quality of supply standards 9.4.1 Supply voltage

Measurements on the LV network indicate that a number of sites exceed the V99% values when measured to AS 61000.3.100. Under the ongoing 230 Volt migration program Ausgrid is currently undertaking the following activities to lower the LV across the network and deliver network functional compliance: • Lowering of the Zone substation 11kV float voltages • Change of Distribution transformer tap settings to deliver the correct 99th percentile voltage (to AS 61000.3.100). Tap setting changes are carried out in conjunction with other maintenance works to constrain costs to the community. Tap setting changes will be carried out earlier in the case of customer complaints that are identified to be due to higher voltages at the Distribution transformers (for example where a customer has installed a PV Solar system that is limiting export due to AS/NZS 4777 settings). In some cases where transformers have insufficient tapping range or because of physical condition of the transformer, a replacement will be carried out. 9.4.2 Flicker, Harmonics and Unbalance Ausgrid monitors customer complaints and resolves any supply quality issues as they arise.

9.5 Compliance with quality of supply standards Under the Standard Form Customer Connection Contract with Ausgrid, our low voltage network customers are required to comply with the requirements of the Service and Installation Rules of NSW and any other reasonable Ausgrid requirements. Consistent with those Rules and our rights under the Contract, Ausgrid requires our customers to ensure that: • their electrical installation does not adversely affect Ausgrid’s network or other customers’ installations, and • that any audible or electronic noise generated by their electrical installation does not breach relevant laws or adversely affect others. If disturbances on the network are caused by more than one customer, Ausgrid will establish overall limits for the interference by each customer, and customers who exceed their limits are required to rectify the situation. Ausgrid’s network modelling process includes checks for voltage compliance on the high voltage network and our internal standards specify compliance requirements for low voltage. Customer quality of supply complaints are reviewed and corrective action taken as necessary. The process for managing supply quality emission limits for major customer connections is generally dictated by the National Electricity Rules (NER) requirements for connection agreements. Ausgrid is required to provide a 20 day turnaround on responses to connection enquiries under the NER. Limits for automatic and minimum access standards for supply quality are included in Ausgrid’s response to the connection enquiries. There are different rules which apply to network customers and registered generators. However, generally the allocation of emission limits for customers and generators are defined in NER clauses S5.1.5-5.1.7. Supply quality requirements for connections are based around the following access standards: • Automatic Access Standards • Minimum Access Standards • Negotiated Access Standards.

For Generators, allocation limits are defined according to NER Clauses S5.2.5.2. For network customers, allocation limits are defined according to NER Clauses S5.3.7 and S5.3.8. For both generators and customers, harmonic and flicker allocations are based on the AS/NZS61000.3 series of documents. For voltage unbalance the proposed approach within Ausgrid is to follow (SA/SNZ) TR IEC61000.3.13, which mirrors the Stages 1-3 approach of the harmonic and flicker standards. The process for achieving compliance with the prescribed supply quality allocation limits is likely to be an iterative process, with consideration given to alternative connection points, or mitigation measures, should initial investigations indicate non-compliance. Where necessary this may involve a reassessment of limits, or the

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acceptance of a negotiated access. Suitable clauses are included in Ausgrid’s connection agreements to ensure compliance with the supply quality allocation limit via agreed levels of monitoring of the installation, and also for appropriate notification and approval of customers’ planned major equipment changes, such as new distorting loads or power factor correction. It should be noted that the NER provides scope for Ausgrid to subsequently enforce automatic access standards where network conditions change.

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10 Asset management

10.1 Ausgrid’s asset management approach Ausgrid’s vision is to be a leading energy solutions provider, both locally and globally. In providing services to our customers, we manage, operate and maintain a widespread electrical network that consists of a large variety of assets. We manage the assets across our network using a systematic risk based, whole of life approach to ensure that the services that we provide are safe, reliable and efficient and meet the needs of our customers and stakeholders. This approach also ensures we deliver and align with the National Electricity Objective and our regulatory and legal requirements, in particular obligations under the WHS Act 2011 and associated regulations, the Electricity Supply (Safety and Network Management) Regulation 2014 (NSW), the National Electricity Law (NEL) and the Electricity Supply Act 1995 (NSW). Our asset management system leverages the capabilities, policies and standards that have been developed over the last fifteen years, in combination with the current state of the network, the increasing availability of network information, and the changes in context of the external operating environment. It is underpinned by a framework that ensures alignment from the leadership, management and culture of the organisation through to the achievement of the asset management objectives. This is achieved through fit for purpose systems and processes, and a clear framework of governance and assurance. Sound and efficient asset management processes and methods have further enabled Ausgrid to transparently demonstrate to industry regulators the prudence and efficiency of our expenditure as it relates to specific assets. Our asset management system, including the strategies, models and processes adopted by Ausgrid, has been certified to conform with the requirements of AS ISO 55001:2014 Asset Management – Management Systems – Requirements in accordance with our Distribution Licence Conditions. 10.2 Risk management strategies The asset management objectives captured within the Asset Management System align to the organisation’s objectives and risk appetite. Asset decisions are informed through structured risk assessments in accordance with the Risk Management Board Policy and Risk Management Framework. Ausgrid’s asset management approach utilises risk management techniques to manage risk within the organisation’s Risk Appetite Statement. Risk management techniques applied to inform asset decision making consistent with the organisation’s legislative responsibilities and AS/NZS ISO 31000-2018 Risk Management – Principles and Guidelines for managing risk. Ausgrid applies numerous techniques for managing risk at various scales, leading to various decision pathways across the life cycle of an asset. The asset management system draws on AS/NZS IEC 31010:2020 Risk management — Risk assessment techniques (IEC 31010) to guide a structured approach to decision making. Risk management techniques such as reliability centred maintenance and cost benefit analysis are used to evaluate risks and determine maintenance and investment requirements respectively. An overview of significant asset class investment strategies are outlined in the following sub-sections. 10.2.1 Sub-transmission underground cable strategy Ausgrid’s sub-transmission cables are an essential part of our supply network. Ausgrid has approximately 1,086km of sub-transmission cables with the majority operating at either 33kV or 132kV and a small number at 66kV.These assets cannot routinely be taken out of service except for brief periods necessitated by the need for maintenance and repair, particularly those which operate at 132kV supplying the inner metropolitan area of Sydney. There are four cable technology types used for these cables – these are listed below (from oldest to youngest type): • 242km of self-contained fluid filled (‘SCFF’) cables • 71km of gas pressure cables • 253km of paper insulated, lead covered (‘paper lead’) cables • 519km of cross-linked polyethylene (‘XLPE’) cables Approximately 49% of Ausgrid sub-transmission cables operate at 132kV and many of these form the critical backbone of the sub-transmission network. Failure of multiple 132kV cables can have significant impacts upon our customers, particularly in the Sydney CBD and surrounding urban areas.

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A risk assessment has been undertaken on sub-transmission cables utilising an asset failure probability model, consequence assessment and justified through cost benefit analysis. From the assessment, SCFF and gas pressure cables are approaching end of life and have been forecast for retirement / replacement. SCFF cables mostly operate at 132kV, however, there are smaller lengths which operate at 66kV. Due to the environmental risks posed by these cables, Ausgrid consults with the Environmental Protection Agency (EPA) in order to take reasonable steps and exercise due diligence regarding the management of the environmental risks. The cost benefit analysis takes into consideration: • the unavailability of individual SCFF cables (failure probability), • condition of individual SCFF cables primarily based on their level of fluid leakage and the condition of the cable serving, • network restoration and repair times for failures and defects, • the environmental risk from individual cables, in particular those crossing major waterways, and • the unserved energy (customer reliability impacts) which are realised in the event of an asset failure Gas pressure cables equate to approximately 7% of Ausgrid sub-transmission cables and they all operate at 33kV. The failure of mechanically fatigued joints, degradation of the cable system has resulting in increasing gas leakage rates and the lengthy restoration and repair times, support the retirement of gas pressure cables. As supported by cost benefit analysis, retirement of all remaining gas pressure cables is expected in the next 10-15 years. Ausgrid also has a substantial population of paper lead cables which all operate at 33kV. These cables formed the backbone of the sub-transmission network at its inception and remain relatively reliable despite their age, with some sections up to 90 years old. The lifespan of these cables is generally considered to be approximately 80 years, however, individual circuits may be retired prior to reaching this age based on condition (issues related to corrosion of the lead sheath or loss of resistance in the paper insulation) as support by cost benefit analysis and other network needs. XLPE cables are the current technology being installed for 33kV, 66kV and 132kV circuits. Ausgrid has been utilising this cable technology for approximately 25 years and is expecting a 60 year operating life. There are currently no plans to retire these assets within the planning horizon. 10.2.2 11kV switchgear strategy Between the late 1930s and the early 1970s Ausgrid progressively installed a large number of compound insulated 11kV switchboards with bulk oil circuit breakers (OCB). As technology progressed, air insulated switchboards (non-internal arc classified technology) with bulk oil circuit breakers (OCBs) became widely available and were installed from the late 1960s until the late 1970s, when vacuum circuit breakers (VCB) were introduced. From 2004, internal arc classified switchgear became the accepted industry standard for new installations. This progression of technology has resulted in a corresponding reduction in the risk of catastrophic failure (both likelihood and consequence). This reduction in risk was traded off against a larger construction footprint in a typical urban style Zone Substation. In rural and lower loaded areas, outdoor 11kV switchgear (cubicle or recloser style) has generally been used as this is a more economical design than indoor switchgear in those areas. However due to the increased exposure to local environmental conditions, this type of switchgear has deteriorated over time, leading to more frequent failures and higher maintenance costs. Risk assessments support the retirement for poor condition and high risk 11kV switchgear. Due to the age and condition issues associated with 11kV compound switchboards, these are approaching end of life as supported by cost benefit analysis. Switchgear risks are considered in conjunction with other planning needs to determine the optimal replacement timeframes. The cost benefit analysis takes into consideration: • the unavailability of individual switchboards / switchboard sections, • condition of individual components primarily based on maintenance test results, • network restoration and repair times for failures and defects, • the risks from switchboard failures, and • the unserved energy (customer reliability impacts) which are realised in the event of an asset failure Oil filled circuit breakers pose an additional risk to safety, reliability and secondary asset damage due to the catastrophic nature in which they can fail. To mitigate this risk and defer retirement of older style air insulated switchboards, 11kV oil filled circuit breakers in zone substations are being replaced with vacuum equivalents where practical.

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10.2.3 Additional replacement programs Additional key replacement programs include: • replacement of poles at end of life, • replacement of overhead conductors including service lines, • retirement of low voltage dedicated mains supporting streetlights, • replacement of unreliable low voltage underground cables, • replacement of high voltage oil filled switchgear in distribution substations, and • replacement of CBD distribution equipment. 10.3 Distribution network losses Distribution network losses refer to the difference in energy obtained from the transmission network to that supplied to customers. Ausgrid’s distribution network losses as a percentage of total energy for the 2018/19 financial year was 3.66%16. Electrical energy losses represent a cost to those who produce, consume and transport electricity and therefore it is Ausgrid’s objective to minimise these losses, while maintaining a safe and reliable electricity supply, at minimum cost to the community. When considering potential network projects under the NER’s Regulatory Investment Test for Distribution, Ausgrid must consider changes in electrical energy losses if they are material or may alter the selection of a preferred investment option. Ausgrid’s methodology for calculating losses is published on its website as part of the requirements of the NER to maintain a method for calculating Distribution Loss Factors (DLFs). This methodology is based on a report from consultants Evans & Peck entitled “Ausgrid – Evaluation of Losses in Project Evaluation” . The aim of this methodology is to enable the quantification of incremental values of network loss savings in the assessment of proposed network project options, and the quantification of network losses as required under the RIT-D. Ausgrid’s technical specifications for the assessment of losses for primary plant such as subtransmission transformers, distribution transformers, shunt reactors etc, specify the method of assessing capitalised losses when comparing tender offers from suppliers. 10.4 Obtaining further information on asset management Further information on asset management may be obtained from Ausgrid’s Asset Management Policy (available on request from the General Manger Asset Management), Electricity Network Safety Management System (ENSMS) and Annual Performance Report available on the Ausgrid website.

16 The distribution network losses are reported at the end of each calendar year, using the previous financial year’s accumulated loss data.

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11 Demand management

11.1 Demand management When Ausgrid identifies a network limitation, non-network options are considered as an alternative to the preferred network option. The implementation of a non-network alternative is commonly referred to as demand management in that the solution has historically involved the reduction or modification of customer demand for grid supplied electricity. With rapidly developing alternatives such as advanced solar and battery inverter control, demand management solutions can now include support for voltage unbalance, power factor and harmonics management. In addition, with minimum demand emerging as a potential driver for network investment, demand management solutions also include the shifting of load to periods of low demand to manage minimum rather than maximum demand.

Demand management is an important part of efficient and sustainable network operations; and can help address a network need due to rising customer demand, minimum demand, aging network assets, voltage unbalance or other investment driver. Effective use of demand management reduces the cost to maintain the network and results in lower electricity bills for all customers. There are a range of demand management or non-network solutions available for use by electricity networks. Examples include: • Energy efficiency (e.g. replacing lights with more efficient, lower wattage options); • Demand response (e.g. operating appliances at lower power demand for short periods such as air conditioner load control); • Load response (e.g. shifting load to periods of minimum demand such as at peak rooftop solar generation on low grid demand days) • Operation of embedded generators (including renewable generators); • Energy storage (e.g. batteries); • Power factor correction (a form of energy efficiency); • Load shifting (shifting equipment use from peak to non-peak periods such as off-peak hot water); • Converting the appliance energy source from electricity to an alternative (e.g. switching from electric to gas heating); and • Voltage management (e.g. operation of customer inverters in voltage support modes).

When a review of a network limitation is initiated, a review of options that includes both network and non-network options is completed. The goal is to identify the solution which offers the highest net benefit and meets the required reliability standards. The solution may be: • Modifications or additions to the existing network (i.e. network solution); and/or • Support of the existing network by others (i.e. non-network or demand management solution).

Ausgrid’s planning process assesses network needs across 28 different network areas. Solution options are developed by area for all known network needs to allow for comprehensive solutions to address multiple needs. To ensure a thorough investigation, Ausgrid consults with the community on larger projects about the network requirements and the potential non-network options available. To determine the right balance, we apply the process depicted in Figure 12.1 following. For projects where the preferred network option cost is greater than $6 million, the Regulatory Investment Test for Distribution (RIT-D) process is followed. The orange boxes denote the reports which are published as part of the RIT-D process. For projects where the preferred network option cost is less than $6 million, Ausgrid applies a similar but simplified process appropriate to the cost of the project. The RIT-D process is a cost-benefit test that must be applied to all network investment projects where the most expensive credible option costs more than $5 million. It must be applied by network distribution businesses when assessing the economic efficiency of different investment options in order to select the best option available to meet their network’s needs. This helps to promote better consistency, transparency and predictability in our planning processes and follows the NER rules under Chapter 5.

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Figure 11.1: Demand Management Assessment process

11.2 Demand management considerations in 2020 There were 50 projects in the forward planning period which met Ausgrid’s criteria for demand management consideration. Ausgrid assesses the viability of demand management alternatives for projects which are scheduled for the forward planning period and which meet minimum threshold costs. For one of these projects, assessment for non-network solutions has determined that it is considered likely that demand management will form part of the least cost solution to the need. The assessments for all projects were based upon preliminary assumptions for project costs, unserved energy and other benefits. A full assessment conducted as part of the RIT-D process, including a request for submissions via the Non-Network Options Report or equivalent will occur in future. 11.3 Demand management activities in 2019-20 11.3.1 Demand management projects initiated in 2019-20 There was one (1) demand management project initiated in FY2019-20 that was linked to a network investment need. Project 1: Gillieston Heights In 2019, a network constraint associated with three interconnected 11kV feeders in the Gillieston Heights area, part of the City of Maitland LGA in the Hunter Region of NSW, was deferred using an air conditioning (AC) load control solution implemented for summer 2019/20. A review of this network constraint in 2020 determined that the network investment could be deferred for a further one to three years. Information pertinent to the analysis included a slightly larger network need area, updated demand forecasts indicating an increase in load driven by new residential developments and the ability to increase the level of demand reductions by utilising a market provisioned grid battery and customer behavioural demand response. Current activities Ausgrid is currently implementing a DM program based on a combination of Ausgrid delivered AC load control, market delivered grid battery and behavioural demand response. Cost-benefit assessment indicates it is economically feasible to reduce the load at risk on the relevant 11kV feeders for 1 to 2 summer seasons commencing in summer 2020/21. Further details will be provided in the Ausgrid’s 2020/21 DTAPR publication and DMIS annual report to be published in 2021.

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11.3.2 Demand management projects implemented in 2019-20 There was one (1) demand management project implemented in FY2019-20 that was linked to a network investment need. Project 1: Gillieston Heights As described in Ausgrid’s 2019 DTAPR, Ausgrid identified an emerging network constraint associated with three interconnected 11kV feeders in the Gillieston Heights area, part of the City of Maitland LGA in the Hunter Region of NSW. Based on cost-assessment, Ausgrid determined that demand management was likely to offer a cost-efficient alternative to augmentation of the distribution network.

A Request for Proposal (RFP) was published in April 2019, however, no economically and technically viable solutions were received. Ausgrid then carried out a feasibility analysis into an Ausgrid delivered DM program based on air-conditioning (AC) load control demand response. Further details are provided in Ausgrid’s 2019/20 Demand Management Incentive Scheme (DMIS) annual report which will be published on the AER website at www.aer.gov.au.

11.3.3 Demand management innovation As part of our efforts to explore alternative demand management solutions, Ausgrid investigates potential demand management solutions that may offer cost-effective alternatives to traditional network options. These research projects are funded through the Demand Management Innovation Allowance (DMIA) and approved by the Australian Energy Regulator. A description of the projects is provided in the following table.

Table 11.2: Demand management innovation projects

Project Project Description Name 1 Demand This project aims to test the viability of using non-network options to defer or Management manage the load at risk associated with network investments that involve retiring for or replacing aged assets. Around 90% of Ausgrid’s capital investment Replacement expenditure over the next 5-10 years is related to the retirement or replacement Needs of aged assets and this will be an important project in building demand (“Power2U – management capability for this type of network investment. Solar and Using non-network solutions to manage risk from replacement driven Lighting investments differs markedly from typical overload risk and requires an Incentives innovative approach to build a portfolio of permanent and temporary load Program”) reductions across the daily profile. The project proposes to leverage the capability of market participants, including electricity retailers, solar installers, energy efficiency providers and other key market participants. The project consists of two independent project components: Part A – An incentives program to encourage permanent demand reductions (e.g. additional solar power systems and energy efficiency activity) in a defined geographical area or areas. Part B – Feasibility studies into the use of traditional demand response solutions for a network outage scenario.

The project will be conducted in three phases:

Phase 1: Market engagement and provider selection – invite submissions/proposals from market to clarify specific trial operational issues and select preferred project partners. Establish service contracts with market providers and project partners. Completed in 2018-2019.

Phase 2: Initiate and operate trial activities over a period sufficient to allow the market to develop and deliver outcomes (est. 18 to 24-month period).

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Project Project Description Name Phase 3: Assessment of trial objectives with project partners, reporting and sharing of lessons learned.

With Phase 2 underway during 2019/20, market providers were operating in all project areas. One Market Provider completed their involvement in the project at the end of this 2019-2020 reporting period.

• The results of activities during 2019/20 included:Initial results collated up to the end of Sep 2019 indicated that the customer response to the incentives offered was materially lower than anticipated. At this point, market providers had not achieved any material uptake for the energy efficient lighting offers; and customer response to the Solar PV offers was limited. • Assessment of feedback from customers via the market providers showed that enthusiasm for investment in Solar PV was much greater than for energy efficient lighting. The lead time required for customers to commit to investing in a Solar PV system was longer than anticipated. • There were concerns not all customer segments were being effectively addressed by the selected market providers and the customer mix in selected program area two was insufficient to draw broad trial conclusions.

During the 2019/20 period, the decision was made to make several changes to program operations, including: • Expansion and extension of the project in order to fully test the original objectives and in response to early trial results. Notably, Phase 2 project activities took longer to commence than anticipated, and in order to allow the incentive offer to extend over a period of about 18-24 months, phase 2 activities were extended. • In response to preliminary results and feedback from market providers, the number of market providers operating in trial area two was increased from two to five and the geographic area for this trial area was increased in size. • Increase of the incentive level applied to trial area one to align with that offered in trial area two. • The decision to proceed with the second objective to conduct customer research to explore longer duration demand response has been deferred and will be reassessed once more complete results from the incentive trials are complete.

In addition, following the onboarding of additional market providers, government restrictions relating to COVID-19 commenced. This caused disruption to the project in two different ways. Firstly, it polarized customers into those who suffered under the restrictions, and those whose business increased. For 1-2 months the project was disrupted as neither of these two basic customer groups were pursuing or progressing solar or energy efficiency capital works. Secondly the government stimulus program as it related to instant asset write-offs could potentially have played into the decision-making process for the businesses that did proceed. While anecdotal evidence suggests that this was not the case, it is difficult to conclusively rule in or out.

More information on the trial can be found on Ausgrid’s website at:

https://www.ausgrid.com.au/Industry/Demand-Management/Power2U-Progam.

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Project Project Description Name 2 Battery This project explores whether battery VPP’s can provide reliable and cost Demand competitive sources of demand reductions or voltage support services to defer Response network investment. The three primary objectives of the project include: (“Power2U – • Test whether customer battery systems offer a technically and Battery Virtual commercially viable demand management option. Power Plant Trial”) • Test customer take-up of a network support offer whereby customer battery systems are dispatched to align with network needs. • Investigate and trial the integration of battery management platforms or systems within the Distributed Energy Resource (DER) optimisation platform of Ausgrid’s Advanced Distribution Management System (ADMS). Secondary objectives include: • Better understanding of the types of customer battery systems being installed by early adopters of the technology • Better understanding of the impacts on maximum demand and energy volume for a customer with a battery system with and without a demand response offer. The project is divided into 3 phases to align with the objectives set for the project: • Phase 1 - Battery customer market research (completed in 2018/19); • Phase 2 - Customer trial over 2 to 3 summer seasons; • Phase 3 – Distributed Energy Resource integration with the Advanced Distributed Management System (ADMS) Phase 1 of the trial included collation and analysis of information of battery systems connected to Ausgrid’s network and an exploration of possible offers and contractual arrangements with a range of different market providers (e.g. battery suppliers, aggregators and energy service providers). Phase 1 was completed in 2018/19 and a summary report for this phase is available on Ausgrid’s website at

https://www.ausgrid.com.au/Industry/Our-Research/DMIA-Research-and-trials.

Phase 2 of the project will include customer battery system dispatch and further development of aggregator partnerships. This Phase was initiated in 2018/19.

Activities in phase 2:

A series of dispatches were completed targeting summer and winter peak demand periods, which demonstrated that a sufficiently sized VPP fleet has the potential to provide considerable peak demand reduction. The results also highlighted various areas such as value stacking, battery pre-charging and dispatch timing that should be further explored to optimise the potential of battery VPPs.

Ausgrid has also been exploring the use of real and reactive power discharge from a battery VPP to regulate voltage. As expected, meter voltage responded to real power charge and discharge events. Where the network has high solar PV connections, the batteries can be charged to ‘soak’ up energy to pull volts down. Conversely, under conditions of high network demand and low volts, the batteries can be used to address both issues. Ausgrid has been limited in its capacity to test reactive battery response due to power factor limitations built into the inverters.

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Project Project Description Name Through an open tender process, Ausgrid has expanded the trial from a single VPP provider to three VPP providers, which has allowed Ausgrid to explore a wider variety of VPP platforms and features.

A progress report summarising the results of 2019/20 is available on Ausgrid’s website at https://www.ausgrid.com.au/Industry/Our-Research/DMIA-Research- and-trials.

Phase 3 of the project will focus on the integration of network support dispatch and constraint management into the DER platform of Ausgrid’s Advanced Distributed Management System (ADMS).

3 Peak Time Ausgrid is seeking to assess the effectiveness of a peak time rebate (PTR) offer Rebate in localised areas of the Ausgrid network area on peak demand days. The (Retailer project aims to test whether this option can be used to alleviate location specific Demand short-term network constraints, to defer or reduce the need for longer term Response) network infrastructure upgrades. The primary purpose of this project is to determine the viability of PTR as a demand management solution through building retail partnerships and conducting trials. As such the objectives are to gain an understanding of the: • Scale and density of peak demand reduction offered by PTR under various modelled scenarios for constrained network assets; • Various customer acquisition strategies and the resulting measure of localised PTR customer take-up; • Effectiveness of various customer incentives; • Customer experience; • Reliability and availability of retailer PTR platforms; and • DNSP costs associated with PTR events and payments to PTR providers.

The PTR project will take place across 2 phases, with the first phase commencing in 2020/21.

The first phase of this project will include the implementation of collaborative PTR trials with retailers. These initial trials will take place in 2020/21 and will confirm the functionality of the retailer PTR platforms, provide insight into targeted Retailer customer recruitment strategy and customer behaviour.

Phase 1 of the trial will include suburbs in the Lower Hunter and Newcastle West areas of Ausgrid’s service area. These areas have been selected as they are representative of the residential areas where network needs are commonly found.

The process and timing for demand response events will need to be negotiated with our market partners, but ideally will be customisable to address local network requirements in both Summer and Winter and have sufficient flexibility to reflect network operating arrangements. Identification of processes and contractual arrangements which maximise benefits to networks, Retailers and customers will be a key focus of collaborative efforts.

Phase 2 of the DMIA project will focus on exploring how we can increase the density of customer adoption of this solution in the trial areas to expand learnings with regards to understanding the potential for network support purposes. Phase 1 partnerships may be continued and/or expanded or

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Project Project Description Name alternatively partnerships with other proponents could be established. The later stages of the trial may explore the recruitment of small business customers, modified offer structures, proactive smart meter changeover to increase PTR take-up, modified target geographic areas and other viable options identified in stage 1.

Further details for phase 2 will be determined during phase 1. 4 Stand Alone This project was developed to improve the techniques by which Stand Alone Power Power Systems (SAPS) can be assessed as non-network options for Ausgrid’s Systems demand management investigations and regulatory investment test- distribution (RIT-D) projects.

The primary objective of this project is to develop the tools for performing initial screening of network investments. Secondary objectives include identifying case studies SAPS are a potentially viable alternative to traditional network options.

The project is planned to take place over two years in 2018/19 and 2019/20 in three phases:

Phase 1 - Costs Benefit Assessment tool development for SAPS Phase 1 will involve the development of a suite of tools that can be used to quantitatively assess whether a Stand-Alone Power System is a more cost- effective alternative to a traditional network solution. This phase of the project will provide:

• A whole-of-life SAPS sizing and costing tool that determines the optimum SAPS configuration based on customer interval demand data and a given set of constraints; • A customer interval demand data estimation tool where metered interval data is not available; • A cost-benefit assessment (CBA) tool which will capture all the relevant costs and benefits associated with deploying a SAPS Phase 2 – Case study identification and customer engagement The case study identification phase of the project would commence in parallel with activities to help define the inputs, scope and outputs required for the tools being developed in Phase 1.

The customer engagement phase would develop a customer engagement process and strategy for providing customers with a SAPS solution which would consider how the various ownership options might influence the overall process (customer-owned, third party owned or DNSP owned).Phase 3 – Stand Alone Power Systems pilots In this phase, one or more of the case studies identified earlier could be progressed to a pilot program. The budget for a pilot program has not been included in this proposal and may be funded from Ausgrid’s Network Innovation program funding for the 2019-24 regulatory period.

2019/20 activities

In 2019/20, building upon the whole-of-life SAPS sizing and costing tool and interval data estimation tool of Phase 1, a cost-benefit assessment methodology was developed to screen for SAPS candidate sites, incorporating the relevant costs and benefits associated with deploying a SAPS, including:

• Avoided costs associated with bushfire risk due to network assets traversing bushfire-prone areas; • Avoided costs associated with safety risks due to electrical infrastructure,

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Project Project Description Name • Avoided network asset maintenance costs; • Financial impacts of improved customer reliability; • SAPS installation costs; and • SAPS maintenance costs

Applying this methodology, a total of 18 high voltage feeders supplying over 3,000 distribution substations, equivalent to around 12,600 customers, have been assess for SAPS. Initial results indicate that for around 140 distribution substations, further investigation for SAPS viability is warranted. This will require location-specific confirmation of other factors before SAPS can be deemed viable.

Phase 3 and the customer engagement component of Phase 2 will be completed as part of Ausgrid’s Network Innovation program. Updates on the progress of the SAPS trial will be published on Ausgrid’s website at www.ausgrid.com.au/About- Us/Innovation/NIAC.

5 Electric This 2-year project will explore the potential impacts of electric vehicle (EV) Vehicle charging on the Ausgrid network by supporting an ARENA-funded project called Demand Charge Together and trial demand management options for electric vehicles. Research The primary objectives of the project are:

• Understand and research options for demand management interventions using EV chargers to shift or curtail demand during peak demand periods; and • Conduct a demand management trial based on the research outcomes. The project will be conducted in two phases:

Phase 1 - Charge Together Project support, led by Evenergi in 2019 There are three main activity streams for this project to develop:

• A suite of fleet products which can be provided to fleet managers with all the tools necessary to migrate their fleets to electric vehicles; • A product that will provide individual EV buyers with the tools necessary to make an EV purchasing decision; • An electricity network planning tool to assist Australian electricity network providers in planning and preparing for the impacts of EV charging on their network. Phase 2 – Customer pilot/ trial to commence in 2020 This phase of the project will trial demand management options for electric vehicle charging based on the outcomes of Phase 1.

2019/20 activities: The principal change during 2019/20 was the further development and decision to progress with Phase 2 activities. These activities included the development of collaborative research projects with electricity retailers and other electric vehicle industry partners and engaging an economic consultant to examine potential network pricing options for electric vehicle charging.

The main project activity up to June 2020 included the completion of the ARENA-funded Charge Together Phase 2 component of the project. This included the completion of an online survey with electric vehicle owners in NSW to gather feedback about their opinions and perceived behaviors around their charging and driving patterns of their electric vehicles. The online survey invited electric vehicle owners sourced from a combination of the project’s partners’

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Project Project Description Name membership networks and from selected customers in Ausgrid’s database who had expressed prior interest in taking part in demand management related research.

Survey:

The preliminary results from the survey were that EV owners:

• Were more likely to be living in homes, had a tertiary level of education and were families or couples without children; • Were more likely to choose to charge their EV when it was most convenient for them irrespective of the state of charge of their car battery; • The majority would consider buying a solar system to charge their EV; and • Were interested in participating in potential electric vehicle trials in the future.

EV demand typology

As part of the EVenergi project, and informed by the survey results, an EV demand typology model was developed which offers an improved understanding of the spatial demand from EVs. The model was crafted to focus at a postcode spatial level. The model developed by EVenergi as part of the project included development of five electric vehicle typologies that could be allocated at a local spatial level. The development of a local spatial allocation model allows for improved local forecasting of EV demand for use by the EV industry, market participants, networks, governments and other interested parties. The improved information will accelerate the development of EV solutions for networks, customers, markets and the industry.

Further project development will continue into 2020/21 towards full implementation of all project phases.

6 Digital Energy This project is a 3-year research project being led by Monash University in which Futures Ausgrid is a co-funding and in-kind contributor in partnership with Energy Consumers Australia and Ausnet Services. The project has been granted funding from the Australian Research Council (ARC) due to its innovative combination of research techniques.

The project aims to understand and forecast changing digital lifestyle trends and their impact on future household electricity demand, including at peak times. The project expects to generate new knowledge by employing digital ethnography and sociological theories to investigate how changing social practices will impact on electricity sector planning. This should provide significant benefits, such as lowering the cost of infrastructure spending, and helping secure affordable electricity provision.

The project has 5 key objectives, which are to:

• Understand how Australian household practices (e.g. heating, cooling, entertaining) are changing and likely to change in relation to emerging digital technologies and across different electricity consumer groups. • Identify emerging future scenarios and principles that will affect electricity sector planning in the near-medium (2025-30) and medium-far (2030-50) futures.

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Project Project Description Name • Develop a theoretical and methodological approach to anticipate changing trends in household practices and energy demand, which brings a futures perspective to theories of social practice and digital ethnography. • Develop an industry-relevant forecasting methodology for tracking and anticipating peak electricity demand, and energy consumption more broadly, that incorporates insights from this future-oriented social science research. • Develop practical demand management solutions for Australian electricity network businesses to plan for efficient, cost-effective and reliable networks. The project will take place over 3 years, starting in late 2018/19 and continuing through 2019/20, 2020/21 with completion expected to be in 2021/22.

There are 6 stages to the project that were put forward in the ARC grant proposal:

Stage 1: Digital and energy futures analysis – to inform the ethnographic research and establish trends (Year 1, objective 1)

Stage 2: Digital ethnography with households – with consumer groups in Ausgrid’s and AusNet’s work areas to generate future scenarios and medium-far futures principles (Years 1 and 2, objectives 1, 2 and 3)

Stage 3: Survey supplement for ECA’s annual Energy Consumer Sentiments Survey – (Years 2 and 3) objectives 1, 2 and 3

Stage 4: Scenario innovation workshops – with residential consumers in Ausgrid’s and Ausnet’s networks to update and extend the scenarios and principles (Year 2, objectives 1, 2 and 3)

Stage 5: Modelling and forecasting development – to cross-analyse, translate and refine the findings, and develop a forecasting methodology (Year 3, objectives 3 and 4)

Stage 6: Demand management innovation – to identify opportunities in emerging trends that are likely to impact the affordability and reliability of electricity supply for residential customers (Year 3, objective 5)

In 2019/20, Stage 1 of the project was completed. Monash University has completed the digital and energy futures analysis which involved the desk-based review of 64 digital and energy industry reports from both international and local sources. This review was to gain insights on how digital technology and energy futures are envisioned and to consolidate findings and trends indicated from the reports. The findings also were synthesized into 6 speculative future scenarios.

Ausgrid’s key supporting role in this stage of the project was to provide input to the industry reports to be studied, review and provide input on the speculative future scenarios being developed, verify the energy demand insights and assess from a local distributor’s perspective.

The recruitment survey for the stage 2 ethnographic fieldwork was conducted in March 2020 receiving over 500 responses from Ausgrid customers. The survey asked respondents questions about their energy use, the digital and energy management technologies they used in their homes and general lifestyle questions.

Ausgrid’s key role in Stage 2 activities during the 2019-2020 year were:

• Sample design of customer survey to recruit a diversity of customer types to meet the customer segments being targeted for the ethnographic studies. The sample design included a diversity of household dwelling

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Project Project Description Name types (apartments vs houses) and locations (rural, regional and inner city). • Preparation of customer contact lists according to the sample design • Providing feedback and advice on the survey design in collaboration with Monash University researchers and other project partners • Designing and testing the online survey collection tool • Approaching Ausgrid customers by email and inviting them to the online survey • Collecting customer consent for participation in the detailed qualitative interviews with Monash University

Results from the recruitment survey are currently being analysed and will be published, in collaboration with Monash University and other project partners, as a separate report later in 2020.

The ethnographic fieldwork to be conducted by the Monash University research team is expected to occur early in 2021.

Further project development will continue into 2020/21 towards full implementation of all project phases.

7 Cost This 2-year project will aim to quantify the peak demand reduction benefits from Reflective the introduction of cost reflective network pricing to residential and small Networking business customers to better understand the effectiveness of these pricing Pricing structures as a targeted demand management tool for network investments. The Research network pricing structure under study will include both seasonal time of use and monthly demand pricing structures and be focused on the residential sector for the first phases of the project.

The primary objective of this project is to better understand and quantify the impact of cost reflective network pricing structures on reducing electricity demand at times of peak demand.

Secondary objectives include better understanding of the complementary measures that could be used to increase the effectiveness of these network pricing signals as an effective demand management tool.

The project will be conducted over a 2-year period in three phases:

Phase 1 – Customer research (surveying) and focus groups Phase 1 will involve surveying around 1,000 residential customers and obtaining more detailed information about their appliances, socio-demographics and retail pricing plans. Phase 1 will also involve following up with a sample of customers from the survey to further explore their understanding of pricing plans, energy- use behaviours and responses to these pricing signals.

Phase 2 – Demand reduction study and analysis Phase 2 will involve a more detailed study of the impact of cost-reflective network pricing using historical data from interval and smart meter customers, results from the customer survey above, and further survey work or follow ups with customers from the survey.

The scope of Phase 2 was further developed in 2019/20 to include the engagement of an analytical consultant to develop an analytical approach to studying the historical half-hourly energy consumption data of customers on time of use pricing structures. Further details of this approach are provided below.

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Project Project Description Name Phase 3 – Trial program Phase 3 would involve a trial of complementary measures identified in Phase 1 and Phase 2 that increase the effectiveness of seasonal time of use or monthly demand pricing in reducing peak demand as well as mitigating customer impacts particularly on vulnerable customers.

2019/20 activities

In 2019/20, around 1100 responses from the surveys completed in 2018/19 were provided to Ausgrid. The responses included detailed information about household energy sources and use, electrical appliances, energy efficiency, dwelling characteristics, household demographics, retail energy plans and behavioural indicators. The sample was stratified and weighted to allow extrapolation of results to Ausgrid’s wider customer base (e.g. by linking to ABS census data).

A preliminary analysis of the survey data was completed to help identify complementary measures that might increase the effectiveness of the customer response to pricing signals, however, these Phase 1 activities were paused during 2019/20 to focus on Phase 2 quantitative analysis over the larger group of 340,000 Ausgrid customers exposed to time of use pricing. To achieve this, a consultant was engaged to develop an analytical approach and to deliver preliminary results on the effectiveness of cost reflective network tariffs in reducing residential peak demand.

The consultant developed a panel model approach to analysing a subset of customers with half-hourly electricity consumption data that have changed from a flat tariff to a time of use tariff over the study period. Variables used in the analytical approach included electricity consumption of a customer, dwelling type, electrical retailer, peak consumption response on typical working and non- working summer and winter days as well as weather station information.

The study period spanned June 2017 to August 2019 and used a sample set of 1442 customers due to the tariff transition requirement. The results from this study estimated summer peak demand reductions in the range 2% to 5% depending on customer segment. Winter peak demand reductions displayed wider variation across the customer segments with counter-intuitive results for small and medium sized customers. Large customers were found to have a 3% reduction.

Further project development will continue into 2020/21 towards full implementation of all project phases.

8 Community This project aims to develop a feasibility study and model business case for Battery community batteries as a solution for local network constraints. The program is Feasibility designed to research and develop capability in a new and innovative approach to Study managing network constraints driven by peak load, minimum demand and associated issues with voltage, system frequencies and power quality management, and the need to manage diverse power flows and system security issues. The project was envisioned to include three possible phases:

Phase 1 – Feasibility study and model business case The first phase of the project is to develop a Feasibility Study and Model Business Case for community batteries as a solution for local network constraints.

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Project Project Description Name Phase 2 – Customer Research – quantitative survey and qualitative online forum. The second phase of the project will include a quantitative survey of Ausgrid customers to assess the customer response to the concept of a community battery and to better understand customers’ perceptions and motivations to participate in a potential trial of the concept. This will be followed by in-depth qualitative research which will test specific propositions and service offers with a smaller sub-set of customers from the survey, to inform the customer engagement strategy for Phase 3.

Phase 3 – Community Battery Trial. The outcomes of the feasibility study and customer research will inform the potential for a practical trial of the concept in a possible phase three.

2019/20 activities

Phase 1 – The feasibility study was completed in February 2020. This report assessed the engineering, commercial and industry/market issues for the concept and involved three integrated workstreams; Technical, Regulatory and Commercial. The report is published on Ausgrid’s website at www.ausgrid.com.au/In-your-community/Community-Batteries/Community- battery-feasibility-study.

Phase 2 – During 2019/20, the scope of the customer research was formulated, the procurement exercise completed, and a market research provider selected. In the third and fourth quarter of 2019/20, the online survey was designed and developed in collaboration with the market research company and input from stakeholders. The online survey was put into field in July 2021 and results from the research will be published in a separate report on Ausgrid’s website when complete.

Phase 3 of the trial is being delivered as part of Ausgrid’s Network Innovation program. More information about the Community Battery trial is found on Ausgrid’s website at www.ausgrid.com.au/In-your-community/Community- Batteries. Updates on the progress of the Community Battery trial will be published on Ausgrid’s website at www.ausgrid.com.au/About- Us/Innovation/NIAC.

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11.4 Forecast demand management projects For the forward planning period, a preliminary demand management assessment has determined that non- network alternatives are likely to offer a cost-effective option for two projects. In advance of the need date, a non-network options report will be published on Ausgrid’s website at https://www.ausgrid.com.au/ritd for these projects. 11.5 Demand side engagement During 2019 Ausgrid continued to inform and engage interested parties over a range of activities to improve demand management outcomes in meeting network needs. Our main channel of engagement continued to be through our quarterly e-newsletters to inform stakeholders about our demand management initiatives, research and other relevant industry information. Past e-newsletters can be viewed on our Keep Informed page at https://www.ausgrid.com.au/Industry/Demand- Management/Demand-management-news. In addition, we notified members on our demand management engagement register about our assessments on all RIT-D projects and invited them to submit comments and proposals during the consultation process. This included notifications for 3 RIT-D projects which can be viewed at https://www.ausgrid.com.au/ritd • Mascot • Sydney Airport • Maroubra

Our engagement activities also included our corporate membership with the Clean Energy Council where we presented at a number of CEC industry events to share with peers about our project activities in demand management as well as women in renewables. For further information on our demand management programs and activities please contact Ausgrid’s Demand Management team at [email protected]. For more information on how Ausgrid investigates and implements non-network solutions, please refer to our Demand Side Engagement Document at https://www.ausgrid.com.au/Industry/Demand-Management/Our- demand-management-strategy . 11.6 Embedded generator enquiries and connection applications The following table summarizes embedded generation enquiries and applications that Ausgrid received under NER clause 5.3A.5 and 5.3A.9 during the financial year 2019/20.

Item Description Quantity Connection enquiries received under clause 5.3A.5 46

Applications to connect received under clause 5.3A.9 3

Average time taken to complete applications to connect N/A*

*The connection applications received have not been finalised/processed completely i.e. no offer has been made, we are currently still going through the approval process.

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12 Investments in information technology and communication systems

12.1 Information, Communication and Technology Information, Communication and Technology (“ICT”) provides the critical business systems to enable Ausgrid to perform its network operations, which includes undertaking effective asset management planning, and fulfilling regulatory and statutory reporting obligations. ICT systems are integral to performing functions such as asset lifecycle management, asset operations, customer and market management and financial reporting, with Supervisory Control and Data Acquisition & Network control systems being integral to performing key network activities such as monitoring and managing the electrical network. Information technology also allows Ausgrid to prudently adopt and effectively implement technology that enables Ausgrid to deliver better services to network customers and reduce costs over time. Key ICT systems support the following Ausgrid core business functions:

Domain Description

Asset Lifecycle Asset management is one of Ausgrid’s most critical functions. The asset management Management business function concerns the management of all physical components of Ausgrid’s electrical system across the lifecycle of assets from investment through to retirement/replacement at the component level. It is also tightly integrated with operations and planning at the Network level. The asset management systems are therefore integral to providing services, reliability and quality of supply and protecting the safety of customers, community and employees.

Works Works management refers to the efficient management of Ausgrid’s resources in the delivery Management of services within the Network. It encompasses processes which are tightly associated with the asset management capability described above, scheduling and dispatch, warehousing and mobility.

Market Market management includes all of the processes related to the collection of revenue resulting Management and from the provision of energy distribution services. The main processes in delivering this Customer business capability are metering, revenue management, and network billing. Market Management management also incorporates network pricing, market transactions, meter data management and financial reporting. Customer management includes functions and processes related to customer interactions, connections and disconnections, as well as the provision of a customer contact centre.

Enterprise Commercial and corporate includes functions necessary for executive control and oversight of Management normal organisational functions, such as finance, reporting, strategy development and implementation, human resource management, non-system asset management and property management.

IT Management The effective management of information across Ausgrid has become crucial. The nature of the business dictates that information needs to be collected, managed and analysed in order to provide timely and effective decision support. Information management is also required to satisfy regulatory obligations and core financial and organisational reporting and analysis. Infrastructure provides the backbone to Ausgrid’s business capabilities and systems. It includes all of the hardware, communication, operating systems and devices required to support the business.

Asset Operations System IT provides the core functions regarding provision and development of the Distribution Network Management System (DNMS) and Supervisory Control and Data Acquisition (SCADA) systems, core telecommunication networks (MPLS, 4G) and distribution network monitoring and control.

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12.1.1 ICT investment actual 2019/20 and forecast Throughout the year, key applications and infrastructure have been maintained to enable a reliable, scalable and secure computing platform. These include our SAP applications, enterprise content management platform, customer relationship management platform, supporting Ausgrid critical infrastructure licence conditions, metering systems and data centre and telecommunications technologies. Ausgrid has also commenced the migration of applications from data centres to the cloud. In the development of the forward plan and strategy the following principles were adopted:

• Customer Centric: Knowing our customer to enable us to provide a seamless and efficient service; • User Experience: Enable a secure, capable and reliably mobile experience; • Data Driven Culture: Extract value from data and enhance capabilities; enable self-service analytics capability; • Platforms: Enable business agility with flexible “pay as you go” models; continue the focus on efficiency by Consolidating, Standardising and Automating; • Cyber Security: To protect the network and customer information including compliance with laws and the distributor licence conditions, and to be recognised as the leader in cyber security within in the Power and Utilities industry.

The ICT capex program focuses on following drivers: Comply, Protect, Maintain and Adapt (including transformation) as set out below:

• Comply with licence conditions, laws and regulatory obligations; • Protect the electricity network, our staff and customer information; • Maintain safe, reliable and affordable customer service and business operations; and • Adapting and transforming Ausgrid systems and capabilities to become process efficient and to form data driven customer centric decisions.

The table below contains a summary of actual ICT investment in 2019/20 and forecast investment in 2020/21 through to 2024/25.

ICT Investment actual 2019/20 and forecast 2020/21 to 2024/25 (real $) *

Actual Forecast ($m) ($m)

2019/20 2020/21 2021/22 2022/23 2023/24 2024/25

Total ICT Capital 60.3 45.1 43.3 25.9 28.5 55.7 Investment *Excludes the Advanced Distribution Management System – see below.

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12.2 Advanced Distribution Management System (ADMS) Ausgrid’s distribution network is managed using a group of systems where control room staff integrate various information flows and take consequent actions to maintain the security and stability of the network. The DNMS is the core operational management tool in that group of systems. It is a single vendor and in-house developed hybrid system dating from the 1990s. Ausgrid’s current DNMS control system started development in the 1990’s and has been in use with limited change for over a decade. The DNMS has: • low resilience to cyber-related attack, noting mitigating controls have been applied in line with industry best practice to meet the Critical Infrastructure License Conditions; • high costs to maintain the necessary contemporary cyber security protections; • limited functionality that cannot be easily developed or extended due to insufficient resources with the required expertise and inherent system architecture constraints; • inefficient connection of new types of network equipment due to the lack a modern system providing asset and connection integration capabilities; • high development and support costs, solely funded by Ausgrid; and • difficulty integrating with new applications and technologies to support the evolving network and customer needs. The DNMS has been assessed as being unable to make the transition to deliver support for the core functions required by a modern distribution utility, i.e. Distributed Energy Resource Management (DERMS), Fault Location Isolation and Rectification (FLISR) and Advanced Metering Infrastructure (AMI). Three replacement options for DNMS were considered with the preferred option being to replace current systems with an ADMS. An ADMS platform provides an integrated set of tools to remotely monitor and control the network, manage system outages, improve planned and emergency event management, and optimise fault location and restoration processes. This will allow Ausgrid to provide the services expected by customers and stakeholders in the rapidly changing energy market 12.2.1 ADMS Benefits An ADMS would address the above challenges of our current DNMS. Improved functionality benefits would include: • management of system outages and restoration works; • planned and emergency event management; • situational awareness from power-flow analysis; • network fault location analysis, automated isolation and restoration capabilities; • provision of a platform for the integration of distributed energy resource management systems as well as other corporate systems enabling the Distribution System Operator (DSO) construct; • an ability to better integrate with Ausgrid’s enterprise systems to ensure a consistent real time situational view (that is not dependant on staff entering and updating information in multiple systems); and • the ability to use digitised switching instructions which would enable non-verbal communications between the control room and field operators. The core benefits assessed in the business case for an ADMS implementation are described in the following table.

Benefit Description

Risk Mitigation Mitigates legacy-system risk (including cyber risk) to as low as reasonably practical

Operational Drives significant operating efficiencies across the major operational groupings Efficiency

Enabling ADMS provides a platform for existing system and process capability integration and enables Platform simple integration of future capabilities

Safety Greater visibility of the operational state of the network and aligned data will improve safety by providing all personnel operating on the network with improved situational awareness

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Benefit Description

Customer Helps meet increasing customer expectations via the provision of accurate and timely outage information through the ADMS which would be in real-time between field operations and customers using our online outage information systems and the contact centre

12.2.2 ADMS Program Implementation The overall program (Program) is managed via a Program Delivery Management Group reporting to an Executive Steering Committee (ESC). The Program will be delivered via a series of phases between January 2019 and March 2024. The high-level objectives of each phase are described in the following table:

Phase Description Timing

1 Replacement of DNMS - this delivers mission-critical monitoring January 2019 to July and control functionality (SCADA) 2021

2 Replacement of Outage Management System (OMS) July 2019 to January 2023

3 Advance Applications – this delivers Automated Fault Detection March 2021 to March and Isolation Restoration and advanced applications to enhance 2024 the optimisation of the network, e.g. Distribution Energy Resource Management.

The table below contains a summary of actual and forecast investment in from 2018/19 through to 2023/24.

Forecast Capex Costs including contingency & overhead costs (nominal $):

Actual Forecast ($m) ($m)

2019/20 2020/21 2021/22 2022/23 2023/24 2024/25

Advance Distribution Management System 24.5 26.5 18.8 13.4 10 1.1 (ADMS)

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12.3 Network Asset Digitisation The implementation of the Network Asset Digitisation Program will deliver a digital twin of Ausgrid’s overhead network that will enable a range of cost efficiencies within network planning, design and works delivery. It is focused on six fundamental streams to acquire accurate network asset data, integrate various information sources and model into a virtual world accessible to staff and relevant third parties to better inform business decisions and drive efficiencies. These streams are:

• Data acquisition • Data management • Establish asset digital twin • Analytics and insights • Reporting • Platform development. The data acquisition activities will rapidly increase the volume and accuracy of asset information, requiring the alignment of current asset information with the establishment of a single asset data model. This model will build upon work conducted as part of the ADMS project and enable the value of this information to be maximised for users and ongoing system implementations. The use of an aligned model will also enable the rapid integration of asset information between systems, reducing effort for users to access and update information. This program includes minor enhancements to existing system integration to streamline data access and update processes. 12.3.1 Network Asset Digitisation Benefits Ausgrid manages a substantial set of asset information to enable efficient and effective business operations. Asset information is recorded and processed into asset management systems from:

• over 5 million recorded assets; • over five hundred thousand inspections/site visits annually; and • hundreds of measurements per day from nearly a million network points. Information from these assets and inspections is currently collected through both automated and manual processes. However, recent advances in technology such as Light Detection and Ranging (LiDAR), panoramic imagery and processing, 3D modelling, machine learning algorithms and capture techniques are allowing utilities to develop much more comprehensive and accurate data sets at significantly reduced costs. A business case was developed assessing the economic benefit to customers as part of the FY20-24 revised regulatory proposal. This process also included an independent assessment of the modelling, assumptions and likely realisation of benefits by GHD. The independent report concluded that the technology and capability was proven in Australia and internationally, the inputs used established supplier costs and the benefits identified utilised a conservative approach suitable to offset any potential overstatement. The benefits of implementation of the Network Digitisation program include:

• Improving capital efficiency from reduced planning and design effort for overhead line investigation and replacement activities; • Improved network reliability and reducing network risk (outage, fire-starts, emergency response) from identification and prioritisation of defects and the installation of LV spreaders where advantageous in non- bushfire areas; • Reduced capital and operational expenditure associated with vegetation encroachments; • Reduced operational expenditure by optimising vegetation management cycles; and • Information partnering with RMS and local councils. 12.3.2 Network Asset Digitisation Program Implementation Ausgrid has undertaken trials of the latest LiDAR and imagery technology to capture a representative sample of Ausgrid’s overhead assets and test the accuracy of information, available analytics and digital twin platforms utilised to represent these assets. Learnings from these trials have been used to inform the development of this program. The implementation of this program will be undertaken in three sequential stages:

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• Stage 1 – Initial network asset acquisition, data management and platform development; • Stage 2 – Second cycle of asset acquisition, processing and comparative analytics; and • Stage 3 – Operationalised asset acquisition and data maintenance. This approach will provide for review and validation of ongoing benefit realisation prior to the implementation of subsequent stages. Each data acquisition and analysis cycle will be delivered in a single stage as shown below. Program delivery stages

The estimated program costs are provided in the table below. Program cost estimates including contingency & overhead ($m, nominal)

FY21 FY22 FY23 FY24 FY25

Network Digitisation 4.1 4.2 3.1 1.3 1.3

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Annexure A – Glossary

ADMS Advanced Distribution Management System

AER Australian Energy Regulator

AEMC The Australian Energy Market Commission is the rule maker and developer for Australian energy markets AEMO Australian Energy Market Operator

CBM Condition Based Maintenance

DER Distributed Energy Resources

DLF Distribution Loss Factor

DPAR Draft Project Assessment Report

DTAPR Distribution and Transmission Annual Planning Report prepared by a Distribution Network Service Provider under the National Electricity Rules DNSP A Distribution Network Service Provider who engages in the activity of owning, controlling, or operating a distribution system, such as Endeavour Energy, Ausgrid and Essential Energy Dual Function Asset Any part of a network owned, operated or controlled by a Distribution Network Service Provider which operates between 66kV and 220kV and which operates in parallel, and provides support, to the higher voltage transmission network and is an asset which forms part of a network that is predominantly a distribution network ENSMS Electricity Network Safety Management System

ESA NSW Electricity Supply Act 1995

EUE Expected Unserved Energy

FMECA Failure Mode Effects and Criticality Analysis

FPAR Final Project Assessment Report

GJ gigajoule One gigajoule = 1000 megajoules. A joule is the basic unit of energy used in the gas industry equal to the work done when a current of one ampere is passed through a resistance of one ohm for one second GWh gigawatt hour One GWh = 1000 megawatt hours or one million kilowatt hours

HV high voltage Consists of 11kV and 22kV distribution assets

JPB Jurisdictional Planning Body

LV low voltage Consists of 400V and 230V distribution assets

kV kilovolt One kV = 1000 volts

kW kilowatt One kW = 1000 watts

KWh kilowatt hour The standard unit of energy which represents the consumption of electrical energy at the rate of one kilowatt for one hour MRA Maintenance Requirements Analysis

MVA (unit of electrical power) Mega Volt Amp

MVAr MVA (reactive). Where quoted as part of a demand forecast, it is assumed that capacitors are in service.

December 2019

MW megawatt One MW = 1000 kW or one million watts

MWh megawatt hour One MWh = 1000 kilowatt hours

N capacity The capacity of a network (or sub-section of network) with all elements in service. N-1 capacity The capacity of a network (or sub-section of network) following a failure of a single critical element. NEL National Electricity Law

NER National Electricity Rules

NTFP National Transmission Flow Path

NTNDP National Transmission Network Development Plan

OCB Oil Circuit Breaker

POE 50 In this document, refers to a demand forecast with a 50% probability of being exceeded (i.e. 1 in 2 years) Primary distribution feeder Distribution line connecting a subtransmission asset to either other distribution lines that are not subtransmission lines, or to distribution assets that are not subtransmission assets pf Power Factor

RCM Reliability Centred Maintenance

RIT-D Regulatory Investment Test for Distribution

SAIDI System Average Interruption Duration Index

SAIFI System Average Interruption Frequency Index

SCFF Cables Self-Contained Fluid Filled Cables

SFAIRP So Far As Is Reasonably Practicable

SOO Statement of Opportunities

STPIS Service Target Performance Incentive Scheme

STS Subtransmission Substation

Subtransmission Any part of the power system which operates to deliver electricity from the higher voltage transmission system to the distribution network and which may form part of the distribution network, including zone substations Subtransmission system Consists of 132kV, 66kV and 33kV assets, including dual function assets

TNSP Transmission Network Service Provider

V volt A volt is the unit of potential or electrical pressure

VCB Vacuum Circuit Breaker

VCR Value of Customer Reliability

W watt A measurement of the power present when a current of one ampere flows under a potential of one volt XLPE Cross-linked Polyethylene

ZS Zone substation

December 2019

Annexure B – Reliability and Performance Licence Conditions

The Reliability and Performance Licence Conditions for Electricity Distributors came into effect on 1 July, 2014 and repeal Schedule 1 of the former Design, Reliability and Performance Licence conditions.

December 2019

SCHEDULE OF MINISTERIALLY IMPOSED LICENCE CONDITIONS FOR THE OPERATOR OF A TRANSACTED DISTRIBUTION SYSTEM

This schedule provides a list of conditions which the Minister has determined to impose pursuant to clause 6(1)(b) of Schedule 2 of the Electricity Supply Act 1995 (the Act) on the operator of a transacted distribution system under the Electricity Network Assets (Authorised Transactions) Act 2015. In addition to Ministerially-imposed conditions, licensees are subject to obligations imposed by the Act, Regulations and associated regulatory instruments which include (without limitation) an obligation to comply with requirements imposed by or under regulations made pursuant to section 111A of the Environmental Planning and Assessment Act 1979.

GENERAL CONDITIONS

1 Operate within Distribution District At all times this Licence is in force, the Licence Holder must ensure that it and all other network operators of its distribution system only operate a distribution system: (a) within its distribution district as set out in Schedule 3 of the Act; (b) within such other areas outside of its distribution district in which the Licence Holder operates a distribution system as at the date of this Licence, as set out or described in Schedule 1 to these conditions; and (c) within such other areas outside of its distribution district as agreed and authorised by the Tribunal and the Licence Holder for the relevant distribution district.

2 National Electricity Market registration At all times this Licence is in force, the Licence Holder must ensure that it and all other network operators of its distribution system: (a) are registered or exempt from the requirement to be registered as a Network Service Provider under the National Electricity Rules; or (b) hold any equivalent authorisation or right of participation in any national electricity market, granted by the person responsible for the granting of such an authorisation or right of participation under any legislation enacted for the purpose of introducing such a market.

3 Technical and prudential criteria The Licence Holder must, for the duration of this Licence, ensure that it and all other network operators of its distribution system satisfy the technical and prudential criteria that each entity is required to meet as a condition of its registration or exemption, or equivalent authorisation or right of participation in any national electricity market, referred to in condition 2.

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RELIABILITY AND PERFORMANCE CONDITIONS

4 Network overall reliability standards

4.1 A Licence Holder must not, when excluded interruptions are disregarded, exceed in a financial year the SAIDI average standards that apply to its feeder types.

4.2 A Licence Holder must not, when excluded interruptions are disregarded, exceed in a financial year the SAIFI average standards that apply to its feeder types.

5 Individual feeder performance

5.1 This condition applies where one or more of the feeders of a Licence Holder exceed the relevant individual feeder standards for any 12 month period ending at the end of March, June, September or December, when excluded interruptions are disregarded.

5.2 A Licence Holder must: (a) investigate the causes for each feeder exceeding the individual feeder standards; (b) by the end of the quarter following the quarter in which the feeder first exceeded the individual feeder standards, complete an investigation report identifying the causes and as appropriate, any action required to improve the performance of each feeder to the individual feeder standards; (c) complete any operational actions identified in the investigation report to improve the performance of each feeder against the individual feeder standards by the end of the third quarter following the quarter in which each feeder first exceeded the individual feeder standards; (d) except as permitted by condition 5.2(e), where the investigation report identifies actions, other than operational actions, required to improve the performance of each feeder to the individual feeder standards, develop a project plan, including implementation timetable, and commence its implementation by the end of the second quarter following the quarter in which the feeder first exceeded the individual feeder standards; (e) consider non-network strategies which provide reliable outcomes for customers. Where found by the investigation report to be equal or more cost-effective than the lowest cost feasible network option such strategies shall be adopted rather than network augmentation options; (f) ensure that the implementation timetable for the network project plan or alternative non- network solutions is as short as is reasonably practicable; (g) where all reasonable steps to improve supply reliability have been taken, the costs of further actions to rectify the non-compliance must be subject to a cost benefit analysis. Where such analysis does not provide a positive benefit, no further action will be taken to improve the feeder’s performance and the ongoing non-conformance with the individual feeder standards will be reported to the Minister by the Licence Holder.

5.3 The investigation report is to include a documented rectification plan where action is found to be justified in order to improve the performance of a feeder to the individual feeder standards. The action that is required may involve work to other network elements, or may involve only repair or maintenance work where capital works are not warranted and take into account any one-off events and previous performance trends. kyys A0137729916v5 120465441 25.6.2015 page 4

6 Customer service standards

6.1 A Licence Holder must pay the sum of $80 to a customer on each occasion when the Licence Holder exceeds the interruption duration standard at the customer’s premises and the customer has made a claim to the Licence Holder within three months of the interruption ceasing.

6.2 A Licence Holder must pay the sum of $80 to a customer where the Licence Holder exceeds the interruption frequency standard at the customer’s premises in a financial year and the customer has made a claim to the Licence Holder within three months of the end of the financial year to which the interruptions relate.

6.3 A Licence Holder must determine a claim for payment under condition 6, and notify the customer of the determination in writing, within one month of receipt of a claim. For customers eligible for payment, the notice of determination must include the amount to be paid, the manner of payment and the timing of payment. Where the claim is not paid (whether in part or in full), the notice of determination must include reasons for the decision.

6.4 A Licence Holder is required to take reasonable steps to make customers aware of the availability of payments on the terms set out in condition 6. Reasonable steps include, as a minimum, publication of information on the Licence Holder’s website and annual newspaper advertisements. On request from a customer, a Licence Holder must provide written information on the availability of payments on the terms set out in condition 6.

6.5 A Licence Holder is required to make only one payment of $80 to a customer per premises in a financial year for exceeding the interruption frequency standard.

6.6 A Licence Holder is required to pay no more than $320 under condition 6 to a customer per premises in any one financial year.

6.7 A payment under this condition does not: (a) in any way alter or diminish any rights that a customer may have against any person under any trade practices or other applicable legislation, common law or contract; (b) represent any admission of legal liability by the Licence Holder; or (c) alter, vary or exclude the operation of section 119 of the National Electricity Law or any other statutory limitations on liability or immunities applicable to a Licence Holder.

6.8 Customers who are eligible for payments under this clause are limited to those customers who are supplied electricity through a metered connection point on an electricity distributor’s system.

7 Performance monitoring and reporting

Network overall reliability standards report

7.1 A Licence Holder must submit a network overall reliability standards quarterly report to the Tribunal within one month of the end of each quarter.

7.2 Each network overall reliability standards report must include the following matters for the previous 12 month period to the end of that quarter: (a) performance against the SAIDI average standards and SAIFI average standards by feeder type, disregarding excluded interruptions; kyys A0137729916v5 120465441 25.6.2015 page 5

(b) reasons for any non-compliance by the Licence Holder with the network overall reliability standards and plans to improve performance; and (c) any other matter notified by the Tribunal in writing.

Individual feeder standards report

7.3 A Licence Holder must submit, within one month of the end of each quarter, a quarterly individual feeder standards report to the Tribunal on feeders that exceeded the relevant individual feeder standards during the previous 12 month period to the end of that quarter, together with, for each feeder: (a) the date at which the feeder first exceeded the relevant individual feeder standard, together with the actual SAIDI and SAIFI performance of the feeder for the 12 month period; (b) details of the remedial action that the Licence Holder intends taking, or has taken, to improve the performance of those feeders; (c) either of the following: (i) the date of completion, or the date of planned completion, of the remedial action plan; or (ii) details of the investigation and action proposed or undertaken leading to the decision to advise the Tribunal that it is not economically justifiable to bring the feeder performance into compliance with the individual feeder standards; and (d) any other matter notified by the Tribunal in writing.

Customer service standards report

7.4 A Licence Holder must submit a quarterly customer service standards report to the Tribunal on the following matters within one month of the end of each quarter, for the preceding quarter and for the previous 12 month period to the end of that quarter: (a) the number of payments given under condition 6 to customers by each type of area listed in Column 1 of Table 1 of Schedule 5 and by the type of standard, as shown in Columns 2 and 3 of Table 1 of Schedule 5; (b) the number of claims not paid (whether in part or full) under condition 6 by each type of area listed in Column 1 of Table 1 of Schedule 5 and by the type of standard, as shown in Columns 2 and 3 of Table 1 of Schedule 5; and (c) any other matter notified by the Tribunal in writing.

Incident reporting

7.5 A Licence Holder must prepare and submit reports on any incident in accordance with any Reporting Manuals issued by the Tribunal.

Independent audit report

7.6 An independent audit must be conducted after the end of each financial year to audit the Licence Holder’s performance against the: (a) network overall reliability standards; (b) individual feeder standards; and (c) customer service standards. kyys A0137729916v5 120465441 25.6.2015 page 6

7.7 The audit must be conducted in accordance with any Audit Guidelines issued by the Tribunal.

7.8 A Licence Holder is required to nominate a person to conduct the independent audit by written notice given to the Tribunal in accordance with auditor nomination procedures published in any Audit Guidelines issued by the Tribunal.

7.9 The person nominated to conduct the independent audit is to be a person who is: (a) independent of the Licence Holder; and (b) competent to exercise the functions of an auditor in respect of the matters to be audited.

7.10 The nomination of an auditor by a Licence Holder ceases to have effect if the Tribunal advises the Licence Holder, by notice in writing, that the nomination is not acceptable or has ceased to be acceptable.

7.11 The Tribunal may nominate an auditor to carry out an audit, and the person so nominated is taken to have been nominated by the Licence Holder, if: (a) the nomination of an auditor by the Licence Holder ceases to have effect; or (b) the Licence Holder fails to nominate an auditor to carry out the audit in accordance with any requirements specified by the Tribunal by notice in writing to the Licence Holder.

7.12 A Licence Holder must provide a copy of the auditor’s report by 30 September each year to the Tribunal.

General matters concerning reports

7.13 Where the Tribunal determines the format of a report required by this condition, a Licence Holder must submit the report in that format.

7.14 The Tribunal may from time to time publish requirements to be followed by the Licence Holder in respect of reports required by this condition and the Licence Holder must comply with any such requirements.

7.15 The Tribunal may from time to time require, by notice in writing to the Licence Holder, further reports relating to these licence conditions including, without limitation, reports relating to capital expenditure works, network refurbishment and maintenance programs.

7.16 A Licence Holder must provide a report submitted to the Tribunal under this condition to the Minister, if requested to do so by the Minister by notice in writing.

8 Business continuity and disruptions

8.1 The Licence Holder must have a documented system to ensure that it has adequate arrangements in place to identify, assess and manage business continuity risks and manage business disruptions relating to the operation of its distribution system (a Business Continuity Plan).

8.2 The Licence Holder must ensure that it and any other network operator of its distribution system implements and complies with the Business Continuity Plan.

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CRITICAL INFRASTRUCTURE LICENCE CONDITIONS For the purposes of conditions 9, 10 and 11 of this Licence, it is acknowledged that the assets which the Licence Holder operates may constitute “critical infrastructure” being those physical facilities, supply chains, information technologies and communication networks which, if destroyed, degraded or rendered unavailable for an extended period, would significantly impact on the security, social or economic wellbeing of the State of New South Wales and other States and Territories which are from time to time electrically interconnected with New South Wales and other States and Territories. These licence conditions will be reviewed by the Minister from time to time (and where necessary) in consultation with responsible Ministers of the Commonwealth and relevant States and Territories.

9 Substantial presence in Australia

9.1 The Licence Holder must take all practical and reasonable steps to ensure: (a) the maintenance of its distribution system is undertaken solely from within Australia, except where maintenance requires either physical servicing of components offshore or the acquisition of replacement components from outside Australia. In such an instance it is the responsibility of the senior officer responsible for network operations to ensure this maintenance does not impact condition 9.2; and (b) that any third party or non-Licence Holder employee, including individuals/entities from outside Australia, undertaking maintenance of the distribution system is subject to the approval of the senior officer responsible for network operations.

9.2 The Licence Holder: (a) must, by using best industry practice for electricity network control systems, ensure that operation and control of its distribution system, including all associated ICT infrastructure, can be accessed, operated and controlled only from within Australia, and that its distribution system is not connected to any other infrastructure or network which could enable it to be controlled or operated by persons outside Australia; (b) must notify the Commonwealth Representative if it enters into a contract under which it outsources the operation and control of its distribution system, including any associated ICT infrastructure; and (c) will be taken to have satisfied condition 9.2(a) for the period of 12 months after the date of this Licence if the Licence Holder undertakes the steps that are required to be undertaken in that 12 month period as set out in an implementation plan approved by the Minister.

9.3 The Licence Holder must: (a) have at least two directors who are Australian citizens; and (b) have senior officers responsible for (notwithstanding their title): (i) operational technology; (ii) network operations; and (iii) security operations in relation to its distribution system, who are persons residing in Australia and hold an appropriate national security clearance, being a clearance of not less than Negative Vetting Level 1 (or equivalent) issued by the NSW Government on advice from the Australian Government Security Vetting Agency (AGSVA). kyys A0137729916v5 120465441 25.6.2015 page 8

Note: For the purposes of Licence condition 9.3(b): The senior officer responsible for operational technology is the officer whose responsibilities include: • Delivering the Supervisory Control and Data Acquisition (SCADA) capability required to safely and reliably operate the NSW distribution system; • Developing and implementing strategies to manage cyber security and other threats affecting the network operational technology environment; and • Developing systems for effectively managing assets remotely, including but not limited to network switches, condition monitoring and remote interrogation or operation of protection systems and relays; and

The senior officer responsible for network operations, is the officer whose responsibilities include: • The day to day operation, monitoring and maintenance of the distribution system; and • Directing the operational planning, management, control and security of the distribution system.

The senior officer responsible for security operations, is the officer whose responsibilities include: • Approval for the Licence Holder's personnel or other nominated personnel to access the Licence Holder's information systems or physical access to the Licence Holder's premises and associated infrastructure; • Personnel security; and • Managing relationships with Commonwealth and state government agencies.

9.4 The Licence Holder is not in breach of its obligations under: (a) condition 9.3(a) if, in the case of a casual vacancy on the board of directors, the vacancy is filled within two months of the casual vacancy first occurring; (b) condition 9.3 if: (i) following the first issue of these conditions to the Licence Holder; or (ii) any position identified in condition 9.3 being vacated or the relevant person ceasing to satisfy the qualifications set out there for any reason, the Licence Holder: (iii) procures the appointment of a person to the relevant position that the Licence Holder bona fide believes will be able to obtain the required security clearance; and (iv) has procured that the person apply for the required security clearance.

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9.5 The exception in condition 9.4(b) ceases to apply to the Licence Holder if: (a) an appointment and application for national security clearance for the person is not made within 4 months of (as relevant) the first issue of these conditions or the relevant vacancy or disqualification occurring; or (b) if the application referred to in condition 9.5(a) is made and is rejected or withdrawn, the Licence Holder does not procure a replacement application being made within 4 months of that rejection or withdrawal; or (c) the Licence Holder does not procure compliance with condition 9.3(b) in any event with respect to any position within 8 months (or such longer period as approved in writing by the Minister) of (as relevant) the first issue of these conditions or the relevant vacancy occurring.

10 Data security

10.1 The Licence Holder must ensure that: (a) all of its information (being design specifications, operating manuals and the like) as to the operational technology (such as the SCADA system) and associated ICT infrastructure of the operational network is held solely within Australia, and that such information is accessible only by a Relevant Person who has been authorised by the Licence Holder and only from within Australia; and (b) all: (i) data as to the quantum of electricity delivered (both historical and current load demand) from or to any one or more sites (or their connection points); and (ii) personal information within the meaning of the Privacy Act 1988 (Cth), relating to or obtained in connection with the operation of the distribution system by a Relevant Person is held solely within Australia, and is accessible only by a Relevant Person or a person who has been authorised by the Licence Holder.

10.2 The Licence Holder is not in breach of its obligations under conditions 10.1(a) or 10.1(b)(i) if the Licence Holder discloses, holds, uses or accesses information or data, or the Licence Holder allows a Relevant Person approved by the senior officer referred to in condition 9.3(b)(i) to disclose, hold, use or access information or data for the purposes of: (a) disclosure to a recognised stock exchange so that such information is made available publicly in compliance with a binding obligation on the part of the Licence Holder or that Associate to do so; (b) complying with any law of the Commonwealth of Australia, or of any of its States and Territories; (c) disclosure to the financial, accounting, insurance, legal, regulatory and other advisers, auditors, insurers, security trustees and financiers (and each of their advisers) of the Licence Holder, any Associate, and any bona fide prospective purchaser of any interest in, or of any interest in the main undertaking of, the Licence Holder or any Associate, but in each case only to the extent necessary in order for those persons to provide the advisory or other services bona fide required of them; (d) disclosure to participants, regulators and service providers in the electricity sector, provided it is in the ordinary course and in accordance with good electricity industry kyys A0137729916v5 120465441 25.6.2015 page 10

practice, and such information is required by those persons to provide the services or to perform the functions bona fide required of them; (e) providing aggregated data which does not permit identification of sites or groups of sites (or their connection points) or their demand characteristics; (f) allowing a service provider or contractor to hold, use or access information where that arrangement is approved by the Tribunal in writing having regard to whether: (i) the service provider or contractor is reputable; and (ii) the service provider or contractor has data security systems in place to ensure information security is maintained; (g) allowing a service provider or contractor who is a provider to the Licence Holder at the date of this Licence to hold, use or access information for the period of 12 months after the date of this Licence provided, after a transition plan is approved by the Tribunal in writing during that period, the Licence Holder undertakes the steps (if any) that are required to be undertaken in that 12 month period as set out in that transition plan; and (h) such other circumstances as approved by the Tribunal in writing.

10.3 The Licence Holder is not in breach of its obligations under condition 10.1(b)(ii) if a Relevant Person or a person authorised to access the information by the Licence Holder discloses, holds, uses or accesses personal information as permitted by the Privacy Act 1988 (Cth).

10.4 The Licence Holder must ensure that third party data or information (including without limitation communications within the meaning of the Telecommunications (Interception and Access) Act 1979 (Cth), personal information within the meaning of the Privacy Act 1988 (Cth), and closed- circuit television footage) which is indirectly accessed or obtained by the Licence Holder because that third party data or information is transferred by a carrier or other party using the Licence Holder's infrastructure, are held by the Licence Holder solely within Australia, and are accessible only by a Relevant Person or a person who has been authorised by the Licence Holder and, in each case, only from within Australia.

10.5 If the Licence Holder is a Foreign Person, in considering whether to provide or withhold approval under conditions 10.2(f) and 10.2(g), the Tribunal must: (a) notify the Commonwealth Representative that the Commonwealth's approval under conditions 10.2(f) and 10.2(g) is being sought by the Licence Holder; (b) meet with the Commonwealth at such times as reasonably required by the Commonwealth Representative and provide such further details as reasonably required by the Commonwealth Representative; (c) comply with any reasonable consultation protocol established by the Commonwealth Representative regarding matters such as the manner in which meetings, consultations and stakeholder liaison will be managed; and (d) in making the final decision to provide or withhold approval under conditions 10.2(f) and 10.2(g), have reasonable regard to any comments provided by the Commonwealth following any such consultation process, subject to any consultation process under this condition 10.5 not exceeding 60 calendar days from the date of notification under condition 10.5(a).

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11 Compliance with critical infrastructure provisions

11.1 On 31 August each year, or such other date specified by the Tribunal, the Licence Holder must furnish a report to the Tribunal and the Commonwealth Representative detailing whether the Licence Holder has complied with conditions 9 and 10 over the preceding financial year to 30 June.

11.2 The report required under condition 11.1 must be audited by an Approved Critical Infrastructure Auditor by a date specified by the Tribunal. The audit required by this condition 11.2 must be a comprehensive audit and must meet any requirements specified by the Tribunal.

11.3 The Tribunal may provide guidance to the Approved Critical Infrastructure Auditor as to the Licence Holder's practices that have satisfied or will satisfy conditions 9 and 10.

11.4 The report required under condition 11.1 must be accompanied by a certification in writing supported by a resolution of the Board of the Licence Holder that, with respect to the relevant period: (a) the Licence Holder has complied with conditions 9 and 10; or (b) the Licence Holder has not complied with conditions 9 and 10, and certifying the nature and extent of each non-compliance and the steps taken by the Licence Holder to ensure compliance (and to preclude further non-compliance) and the timeframe within which it expects to achieve compliance.

CONDITIONS RELATING TO MANAGEMENT SYSTEMS

12 Maintenance of certified management systems

12.1 Within two years after the date of this Licence, the Licence Holder must have and maintain: (a) an asset management system that is consistent with the International Standard ISO 55001 Asset Management System – Requirements; and (b) an environmental management system that is consistent with International Standard ISO 14001 Environmental Management, which comply with this condition 12.

12.2 The Licence Holder must ensure that, by the time it is required to comply with condition 12.1: (a) its asset management system is certified by an appropriately qualified person to be consistent with International Standard ISO 55001 Asset Management System – Requirements; and (b) its environmental management system is certified by an appropriately qualified person to be consistent with International Standard ISO 14001 Environmental Management.

12.3 The Licence Holder must ensure that, once its asset management system and environmental management systems are each certified in accordance with condition 12.2, the certifications are maintained for the remainder of the duration of the Licence.

12.4 The Licence Holder must notify the Tribunal, in accordance with any Reporting Manuals issued by the Tribunal, of any significant changes it proposes to make to its asset management system or environmental management system.

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13 Implementation of management systems The Licence Holder must ensure that its asset management system and environmental management system are fully implemented and all relevant activities undertaken by it or any other network operator of its distribution system are carried out in accordance with the relevant management system.

CONDITIONS RELATING TO COMPLIANCE, REPORTING AND FEES

14 Reporting in accordance with Reporting Manuals The Licence Holder must prepare and submit reports in accordance with any Reporting Manuals issued by the Tribunal.

15 Complying with Audit Guidelines issued by the Tribunal The Licence Holder must comply with any Audit Guidelines issued by the Tribunal.

16 Compliance management systems The Licence Holder must ensure internal systems are developed and maintained that are capable of effectively managing compliance with its Licence.

17 Compliance with statistical operating obligations The Licence Holder must provide to the Tribunal such operating and statistics and performance indicators as may be required from time to time by the Tribunal. The Tribunal will provide the Licence Holder with reasons for its request when the initial request is made and after that when a request relates to operating statistics and performance indicators that are of materially different type or category to that provided under the initial or subsequent request.

18 Information about compliance with Licence Conditions The Licence Holder must furnish to the Tribunal (at such times and in respect of such periods as the Tribunal may determine and in the manner and form specified by the Tribunal) such information as the Tribunal may determine, to enable the Tribunal to ascertain whether or not the Licence Holder is complying with the conditions of its Licence, the Act or the Regulations.

19 Information about compliance with Employment Guarantees

19.1 The Licence Holder must furnish to the Tribunal (at such times and in respect of such periods as the Tribunal may determine and in the manner and form specified by the Tribunal) such information as the Tribunal may determine, to enable the Tribunal to ascertain whether or not the Licence Holder is complying with the 'Employment Guarantees' set out in Schedule 4 to the Electricity Network Assets (Authorised Transactions) Act 2015.

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19.2 The Licence Holder must comply at its own expense and within a reasonable timeframe nominated by the Tribunal, with any request from the Tribunal to have information provided under condition 19.1 audited by an Approved Auditor.

20 Licence fees

20.1 It is a condition of this Licence that the Licence Holder pay such fees (annual or otherwise) in connection with the holding of the Licence as may be determined by the Minister from time to time.

20.2 The Licence Holder must pay the fees referred to in condition 20.1 in the manner and within the period specified by the Tribunal.

INTERPRETATION AND DEFINITIONS Interpretation In these Licence conditions, unless the context requires otherwise: (a) the singular includes the plural and vice versa; (b) headings are used for convenience only and do not affect the interpretation of these Licence conditions; (c) a reference to a documents includes the document as modified from time to time and any document replacing it; (d) the word "person" includes a natural person and any body or entity whether incorporated or not; (e) references to conditions are references to conditions in these Licence conditions.

Definitions Expressions used in these Licence conditions that are defined in the Act or the Regulations have the meanings set out in the Act or the Regulations. In these Licence conditions: Act means the Electricity Supply Act 1995. Approved Auditor means an auditor nominated in accordance with conditions 7.8 to 7.11 (inclusive). Approved Critical Infrastructure Auditor means an Approved Auditor who has been further approved by the Tribunal as having the necessary experience and expertise in system security or has otherwise demonstrated to the Tribunal's satisfaction the capability to audit compliance with the critical infrastructure licence conditions (being conditions 9, 10 and 11) Associate has the meaning given to that term in the Corporations Act 2001 (Cth). Audit Guidelines means any document setting out audit requirements for Licence Holders which is prepared by the Tribunal and is available on its website at www.ipart.nsw.gov.au as amended from time to time. Business Continuity Plan has the meaning given to it condition 8.1. kyys A0137729916v5 120465441 25.6.2015 page 14

CBD Sydney feeder means a feeder forming part of the triplex 11kV cable system supplying predominantly commercial high-rise buildings, within the City of Sydney. Commonwealth Representative means the First Assistant Secretary, National Security Division, 3-5 National Cct, Barton ACT 2600. customer means a wholesale or retail customer who is supplied electricity through a connection point on an electricity distributor’s system. customer service standards means the customer service standards in Schedule 5 to these conditions. distribution system means the distribution system of which the Licence Holder is a network operator. distribution district has the meaning given to it in Division 2 of Part 7 of the Electricity Supply Act 1995. excluded interruptions means excluded interruptions listed in Schedule 4 to these conditions. feeder means a high-voltage line operating at over 1kV and generally at or below 22 kV that connects between a zone substation and a distribution substation. feeder type means a CBD Sydney feeder, long rural feeder, short rural feeder or urban feeder as the case may be. financial year means the period commencing on 1 July and ending 30 June the following calendar year. Foreign Person has the meaning given to that term in the Foreign Acquisitions and Takeovers Act 1975 (Cth) and the Foreign Acquisitions and Takeovers Regulation 2015 (Cth). individual feeder standards means the individual feeder standards in Schedule 3 to these conditions. interruption means any temporary unavailability of electricity supply to a customer associated with an outage of the distribution system including outages affecting a single premises, but does not include disconnection. interruption duration standards means the interruption duration standards set out in Schedule 5 to these conditions. interruption frequency standards means the interruption frequency standards set out in Schedule 5 to these conditions. Licence means the distributor's licence authorising the Licence Holder to operate its distribution system. Licence Holder means a person who is the holder of a Licence. local government area has the meaning given in the Local Government Act 1993 long rural feeder means a feeder with a total feeder length greater than 200 km which is not a CBD Sydney feeder or an urban feeder. metropolitan means the areas comprising the local government areas and suburbs listed in Schedule 7, but only to the extent that the kyys A0137729916v5 120465441 25.6.2015 page 15

Licence Holder may operate a Distribution System in the relevant areas in accordance with condition 1. major event day has the meaning given in Schedule 6. Minister means the Minister responsible for administering the Act. network overall reliability standards means the requirements imposed under condition 7 of these conditions. non-metropolitan means areas in NSW other than areas defined as metropolitan. planned interruption means an interruption that has been planned by the Licence Holder. quarter means a period of three months commencing 1 January, 1 April, 1 July and 1 October and concluding on the following 31 March, 30 June, 30 September and 31 December dates respectively, as the case may be. Regulations means regulations made under the Act. Relevant Person means the Licence Holder, any other network operator of the distribution system, and any person who is contracted or sub- contracted by the Licence Holder to work on the distribution system. Reporting Manual means any document setting out reporting requirements for Licence Holders which is prepared by the Tribunal and is available on its website at www.ipart.nsw.gov.au as amended from time to time. SAIDI means the average derived from the sum of the durations of each sustained customer interruption (measured in minutes), divided by the total number of customers (averaged over the financial year) of the Licence Holder. SAIDI average standards means the standards set out in item 1, Schedule 2. SAIFI means the average derived from the total number of sustained customer interruptions divided by the total number of customers (averaged over the financial year) of the Licence Holder. SAIFI average standards means the standards set out in item 2, Schedule 2. short rural feeder means a feeder with a total feeder route length less than 200 km, and which is not a CBD Sydney feeder or an urban feeder. suburb means an area defined by boundaries determined and gazetted by the Geographical Names Board of New South Wales. transacted distribution system means a transacted distribution system under the Electricity Network Assets (Authorised Transactions) Act 2015. Tribunal means the Independent Pricing and Regulatory Tribunal of New South Wales established under the Independent Pricing and Regulatory Tribunal Act 1992. urban feeder means a feeder with actual maximum demand over the reporting period per total feeder route length greater than 0.3 MVA/km and which is not a CBD Sydney Feeder. kyys A0137729916v5 120465441 25.6.2015 page 16

SCHEDULE 1 – Authorised Areas The Licence Holder is authorised to operate a distribution system within all areas outside of its distribution district in which the Licence Holder operates a distribution system as at the date of this Licence, including any such areas notified by the Licence Holder to the Tribunal for the purposes of inclusion on any register maintained by the Tribunal.

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SCHEDULE 2 – NETWORK OVERALL RELIABILITY STANDARDS

1. SAIDI Average Reliability Duration Standards (Minutes per customer)

SAIDI (Minutes per customer) AUSGRID Feeder Type CBD Sydney 45 Urban 80 Short-rural 300 Long-rural 700

2. SAIFI Average Reliability Interruption Standards (Number per customer)

SAIFI (Number per customer) AUSGRID Feeder Type CBD Sydney 0.3 Urban 1.2 Short-rural 3.2 Long-rural 6

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SCHEDULE 3 – INDIVIDUAL FEEDER STANDARDS

1. SAIDI Individual Feeder Average Reliability Duration Standards (Minutes per customer)

SAIDI (Minutes per customer) AUSGRID Feeder Type CBD Sydney 100 Urban 350 Short-rural 1000 Long-rural 1400

2. SAIFI Individual Feeder Standards Average Reliability Interruption Standards (Number per customer)

SAIFI (Number per customer) AUSGRID Feeder Type CBD Sydney 1.4 Urban 4 Short-rural 8 Long-rural 10

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SCHEDULE 4 – EXCLUDED INTERRUPTIONS

The following types of interruptions (and no others) are excluded interruptions:

(a) an interruption of a duration of one minute or less; (b) an interruption resulting from: (i) load shedding due to a shortfall in generation; (ii) a direction or other instrument issued under the National Electricity Law, Energy and Utilities Administration Act 1987, the Essential Services Act 1988 or the State Emergency and Rescue Management Act 1989 to interrupt the supply of electricity; (iii) automatic shedding of load under the control of under- frequency relays following the occurrence of a power system under-frequency condition described in the Power System Security and Reliability Standards made under the National Electricity Rules; (iv) a failure of the shared transmission system; (c) a planned interruption; (d) any interruption to the supply of electricity on a Licence Holder’s distribution system which commences on a major event day; and (e) an interruption caused by a customer’s electrical installation or failure of that electrical installation.

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SCHEDULE 5 – CUSTOMER SERVICE STANDARDS

Interruption duration standard: 1. The interruption duration standard is the maximum duration, set out in column 2 of table 1, of an interruption to a customer’s premises located in the relevant area in column 1 of table 1.

Interruption frequency standard: 2. The interruption frequency standard is the maximum number of interruptions in a financial year set out in column 3 of table 1, to a customer’s premises located in the relevant area in column 1 of table 1:

Table 1

Column 1 Column 2 Column 3

Interruption frequency Type of area in Interruption duration standard (number of which customer’s standard (hours) interruptions and hours premises is located of duration)

4 interruptions of greater metropolitan 12 than or equal to 4 hours

4 interruptions of greater non-metropolitan 18 than or equal to 5 hours

Interruptions to be disregarded 3. In calculating the interruption duration standard or the interruption frequency standard the following types of interruptions (and no others) are excluded: (a) an interruption resulting from the following external causes: (i) a shortfall in generation; (ii) a failure or instability of the shared transmission system; (iii) a request or direction from an emergency service organisation; (b) a planned interruption; (c) an interruption within a region in which a natural disaster has occurred and: (i) the responsible Minister has made a declaration of a Natural Disaster enabling the NSW Disaster Assistance Arrangements to apply in respect of that natural disaster for that region; and

(ii) the interruption occurred during the period for which a declaration of a kyys A0137729916v5 120465441 23.11.2016 page 21

Natural Disaster and NSW Disaster Assistance Arrangements were in effect; (d) an interruption caused by the effects of a severe thunderstorm or severe weather as advised by the Bureau of Meteorology. These effects may include the necessary operation of a circuit protection device which interrupts supply to customers in areas not directly impacted by the severe thunderstorm or severe weather. (e) an interruption caused by third party actions other than animal or vegetation interference (e.g. vehicle-hit-pole, vandalism) where the interruption is not also caused by any failure of the Licence Holder to comply with relevant plans, codes, guides or standards (e.g. low conductor clearance).

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SCHEDULE 6 – MAJOR EVENT DAY

The following material is reprinted with permission from IEEE Std. 1366-2012, IEEE Guide for Electric Power Distribution Reliability Indices, by IEEE. The IEEE disclaims any responsibility or liability resulting from the placement and use in the described manner. For the avoidance of doubt and the promotion of consistency, Items “a”, “b”, “c” and “e” listed in Schedule 4 should be removed from daily records before applying the following methodology to calculate a major event day.

Explanation and Purpose The following process (“Beta Method”) is used to identify major event days which are to be excluded from the network overall reliability standards and individual feeder standards. The method is to be used provided that the natural log transformation of the data results closely resembles a Gaussian (normal) distribution. Where this is not the case, Ausgrid may seek the Tribunal’s approval to apply a different threshold value. Its purpose is to allow major events to be studied separately from daily operation, and in the process, to better reveal trends in a daily operation that would be hidden by the large statistical effect of major events. A major event day under the Beta Method is one in which the daily total system (i.e. not on a feeder type basis) SAIDI value (“daily SAIDI value”) exceeds a threshold value, TMED. The SAIDI is used as the basis of determining whether a day is a major event day since it leads to consistent results regardless of utility size and because SAIDI is a good indicator of operational and design stress. In calculating the daily total system SAIDI, any interruption that spans multiple days is deemed to accrue on the day on which the interruption begins. That is, all minutes without supply resulting from an interruption beginning on a major event day are deemed to have occurred in the major event day, including those minutes without supply occurring on following days. Determining a major event day

The major event day identification threshold value TMED is calculated at the end of each financial year for each electricity distributor for use during the next financial year as follows: (a) Collect daily SAIDI values for the last five financial years. If fewer than five years of historical data are available, use all available historical data for the lesser period. (b) Only those days that have a daily SAIDI value will be used to calculate the TMED (i.e. days that did not have any interruptions are not included). (c) Take the natural logarithm (In) of each daily SAIDI value in the data set. (d) Find α (Alpha), the average of the logarithms (also known as the log-average) of the data set. (e) Find β (Beta), the standard deviation of the logarithms (also known as the log-standard deviation) of the data set. kyys A0137729916v5 120465441 23.11.2016 page 23

(f) Complete the major event day threshold TMED using the following equation: TMED = e(α + 2.5β) (g) Any day with daily SAIDI value greater than the threshold value TMED which occurs during the subsequent financial year is classified as a major event day.

Treatment of a major event day To avoid doubt, a major event day, and all interruptions beginning on that day, are excluded from the calculation of an electricity distributor’s SAIDI and SAIFI in respect of all of its feeder types.

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SCHEDULE 7 – LIST OF METROPOLITAN AREAS

1. Local Government Areas ASHFIELD HUNTERS HILL PITTWATER AUBURN HURSTVILLE RANDWICK BANKSTOWN KOGARAH ROCKDALE BAULKHAM HILLS KU-RING-GAI RYDE BLACKTOWN LAKE MACQUARIE SHELLHARBOUR BOTANY BAY LANE COVE STRATHFIELD BURWOOD LEICHHARDT SUTHERLAND CAMDEN LIVERPOOL SYDNEY CAMPBELLTOWN MANLY WARRINGAH CANTERBURY MARRICKVILLE WAVERLEY CANADA BAY MOSMAN WILLOUGHBY FAIRFIELD NEWCASTLE WOLLONGONG GOSFORD NORTH SYDNEY WOOLLAHRA HOLROYD PARRAMATTA WYONG HORNSBY PENRITH

2. Suburbs A. Blue Mountains area

BLACKHEATH LINDEN BLAXLAND MEDLOW BATH BULLABURRA MOUNT RIVERVIEW

FAULCONBRIDGE MOUNT VICTORIA GLENBROOK SPRINGWOOD HAWKESBURY HEIGHTS VALLEY HEIGHTS HAZELBROOK WARRIMOO KATOOMBA WENTWORTH FALLS LAPSTONE WINMALEE LAWSON WOODFORD LEURA YELLOW ROCK

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B. Cessnock-Bellbird area

ABERDARE CESSNOCK BELLBIRD KEARSLEY BELLBIRD HEIGHTS NULKABA C. Kiama area

BOMBO KIAMA HEIGHTS

KIAMA MINNAMURRA KIAMA DOWNS

D. Kurri Kurri-Weston area

ABERMAIN PELAW MAIN HEDDON GRETA STANFORD MERTHYR KURRI KURRI WESTON

NEATH

E. Maitland area

ABERGLASSLYN MOUNT DEE

ASHTONFIELD OAKHAMPTON BOLWARRA OAKHAMPTON HEIGHTS BOLWARRA HEIGHTS PITNACREE EAST MAITLAND RAWORTH HORSESHOE BEND RUTHERFORD LARGS SOUTH MAITLAND LORN TELARAH LOUTH PARK TENAMBIT

MAITLAND THORNTON METFORD WOODBERRY MORPETH

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F. Newcastle Industrial area

FERN BAY WILLIAMTOWN FULLERTON COVE G. Port Stephens area CORLETTE SALAMANDER BAY FINGAL BAY SHOAL BAY NELSON BAY SOLDIERS POINT H. Raymond Terrace area HEATHERBRAE TOMAGO RAYMOND TERRACE I. Richmond-Windsor area BLIGH PARK NORTH RICHMOND CLARENDON RICHMOND HOBARTVILLE SOUTH WINDSOR MCGRATHS HILL VINEYARD MULGRAVE WINDSOR

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Annexure C – Compliance Checklists

December 2019

2020 TAPR - NER v146 REQUIREMENTS CHECKSHEET Section in NER Clause NER Requirements DTAPR Subject to paragraph 5.12.2 (b), by 31 October each year all TNSP's must publish 5.12.2 (a) an TAPR setting out the results of the annual planning review conducted in Throughout accordance with clause 5.12.1. If a Network Service Provider is a TNSP only because it owns, operates or controls 5.12.2 (b) dual function assets then it may publish its TAPR in the same document and at the Throughout same time as its DAPR. 5.12.2 (c) The TAPR must set out: see below the forecast loads submitted by a DNSP in accordance with clause 5.11.1 or as modified 5.12.2 (c)(1) 6.2 in accordance with clause 5.11.1(d), including at least: a description of the forecasting methodology, sources of input information, and the 5.12.2 (c)(1)(i) 6.2 assumptions applied in respect of the forecast loads; a description of high, most likely and low growth scenarios in respect of the forecast 5.12.2 (c)(1)(ii) 6.2 loads; an analysis and explanation of any aspects of forecast loads provided in the 5.12.2 (c)(1)(iii) Transmission Annual Planning Report that have changed significantly from forecasts 6.2 provided in the Transmission Annual Planning Report from the previous year; and an analysis and explanation of any aspects of forecast loads provided in the 5.12.2 (c)(1)(iv) Transmission Annual Planning Report from the previous year which are significantly 6.2 different from the actual outcome; for all network asset retirements, and for all network asset de-ratings that would result in a network constraint, that are planned over the minimum planning period specified in 5.12.2 (c)(1A) 4 clause 5.12.1(c), the following information in sufficient detail relative to the size or significance of the asset: 5.12.2 (c)(1A)(i) a description of the network asset, including location; 4 the reasons, including methodologies and assumptions used by the Transmission Network Service Provider for deciding that it is necessary or prudent for the network 5.12.2 (c)(1A)(ii) 4 asset to be retired or de-rated, taking into account factors such as the condition of the network asset; the date from which the Transmission Network Service Provider proposes that the 5.12.2 (c)(1A)(iii) 4 network asset will be retired or de-rated; and if the date to retire or de-rate the network asset has changed since the previous 5.12.2 (c)(1A)(iv) 4 Transmission Annual Planning Report, an explanation of why this has occurred; for the purposes of subparagraph (1A), where two or more network assets are: (i) of the same type; (ii) to be retired or de-rated across more than one location; 5.12.2 (c)(1B) (iii) to be retired or de-rated in the same calendar year; and 4 (iv) each expected to have a replacement cost less than $200,000 (as varied by a cost threshold determination), those assets can be reported together... 6.1.2, 5.12.2 (c)(2) planning proposals for future connection points; 7.1, 7.5 a forecast of constraints and inability to meet the network performance requirements set 5.12.2 (c)(3) in schedule 5.1 or relevant legislation or regulations of a participating jurisdiction over 1, 6 3, and 5 years, including at least: 5.12.2 (c)(3)(i) a description of the constraints and their causes; 6 5.12.2 (c)(3)(ii) the timing and likelihood of the constraints; 6 a brief discussion of the types of planned future projects that may address the 5.12.2 (c)(3)(iii) 6 constraints over the next 5 years, if such projects are required; and sufficient information to enable an understanding of the constraints and how such 5.12.2 (c)(3)(iv) 6 forecasts were developed; in respect of information required by subparagraph 5.12.2 (c)(3), where an estimated 5.12.2 (c)(4) reduction in forecast load would defer a forecast constraint for a period of 12 months, 6 include: 5.12.2 (c)(4)(i) the year and months in which a constraint is forecast to occur; 6 the relevant connection points at which the estimated reduction in forecast load may 5.12.2 (c)(4)(ii) 6 occur; 5.12.2 (c)(4)(iii) the estimated reduction in forecast load in MW needed; and 6 a statement of whether the TNSP plans to issue a Request For Proposals for augmentation or a non-network option identified by the annual planning review 5.12.2 (c)(4)(iv) 6 conducted under clause 5.12.1 (b) and if so, the expected date the request will be issued;

Page C1 of C6 2020 TAPR - NER v146 REQUIREMENTS CHECKSHEET Section in NER Clause NER Requirements DTAPR for all proposed augmentations to the network the following information, in sufficient 5.12.2 (c)(5) detail relative to the size or significance of the project and the proposed operational date 6 of the project: project/asset name and the month and year in which it is proposed that the aset will 5.12.2 (c)(5)(i) 6 become operational; the reason for the actual or potential constraint, if any, or inability, if any, to meet the network performance requirements set out in schedule 5.1 or relevant legislation or 5.12.2 (c)(5)(ii) 6 regulations of a participating jurisdiction, including load forecasts and all assumptions used; the proposed solution to the constriant or inability to meet the newtork performance 5.12.2 (c)(5)(iii) 6 requirements identified in subparagraph (ii), if any: 5.12.2 (c)(5)(iv) total cost of the proposed solutions; 7 whether the proposed solution will have a material inter-network impact. In assessing whether an augmentation to the network will have a material inter-network impact a 5.12.2 (c)(5)(v) 6.1.3 TNSP must have regard to the objective set of criteria published by AMEO in accordance with clause 5.21 (if any such criteria have been published by AEMO); and other reasonable network options and non-network options considered to address the actual or potential constraint or inability to meet the network performance requirements identifield in subparagraph (ii), if any. Other reasonable network and non-network options 5.12.2 (c)(5)(vi) 6.3, 6.4, 6.5 include, but are not limited to, interconnections, generation options, demand side options, market network service options and options involving other transmission and distribution networks.

the manner in which the proposed augmentations and proposed 5.12.2 (c)(6) replacements of network assets relate to the most recent Integrated 3.6.1 System Plan

for proposed new or modified emergency frequency control schemes, the manner in 5.12.2 (c)(6A) 6.6 which the project relates to the most recent power system frequency risk review; information on the Transmission Network Service Provider’s asset management 5.12.2 (c)(7) 10 approach, including: 5.12.2 (c)(7)(i) a summary of any asset management strategy employed by the Transmission Network 10 a summary of any issues that may impact on the system constraints identified in the 5.12.2 (c)(7)(ii) Transmission Annual Planning Report that has been identified through carrying out 10 asset management; and information about where further information on the asset management strategy and 5.12.2 (c)(7)(iii) 10 methodology adopted by the Transmission Network Service Provider may be obtained. 5.12.2 (c)(8) any information requirement to be included in an TAPR under: see below clauses 5.16.3© and 5.16A.3 in relation to a network investment which is determined 5.12.2 (c)(8)(i) 7.4 to be required to address an urgent and unforeseen network issue; or clauses 5.20B.4(h) and (i) and clauses 5.20C.3(f) and (g) in relation to network 5.12.2 (c)(8)(ii) investment and other activities to provide inertia network services, inertia support N/A activities or system strength services. emergency controls in place under clause S5.1.8, including the Network Service 5.12.2 (c)(9) Provider's assessment of the need for new or altered emergency controls under that 6.7 clause; 5.12.2 (c)(10) facilities in place under clause S5.1.10; 6.6 an analysis and explanation of any other aspects of the Transmission Annual Planning 5.12.2 (c)(11) Report that have changed significantly from the preceding year's Transmission Annual 2.5 and 4 Planning Report, including the reasons why the changes have occurred; and the results of joint planning (if any) undertaken with a Transmission Network Service Provider under clause 5.14.3 in the preceding year, including a summary of the process 5.12.2 (c)(12) 8.1 and methodology used by the Transmission Network Service Providers to undertake joint planning and the outcomes of that joint planning.

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Section in NER Clause NER Task Description DTAPR 5.13.2 A DNSP must publish a Distribution Annual Planning Report: See below 5.13.2(a) by 31 December each year Throughout 5.13.2(b) including results of annual planning review Throughout 5.13.2(c) with information as described in Schedule 5.8 Throughout 5.13.2(d) unless separately reported as required by legislation n/a must include contact details for a suitably qualified staff member to whom queries may 5.13.2(e) inside cover be directed 5.13.3 Distribution system limitation template 5.13.2(a)-(c) Requirements of the template that the AER must provide n/a At the same time as it publishes its Distribution Annual Planning Report each year, a Distribution Network Service Provider must publish a report which contains the 2.6, 5.13.2(d) information specified in paragraph (c) in the form required by the system limitation Ausgrid website template. Information regading the Distribution Network Servcie Provider and its network, S5.8(a) See below including: S5.8(a)(1) provide a description of Ausgrid’s network 2.1 & 2.2 S5.8(a)(2) provide a description of Ausgrid's operating environment 2.1 & 2.2 S5.8(a)(3) provide a description of the number and types of distribution assets 2.2 provide methodologies used in preparing the Distribution Annual Planning Report, S5.8(a)(4) including methodologies used to identify system limitations and any assumptions 2.3 & 2.4 applied provide analysis and explanation of any aspects of forecasts and information provided in S5.8(a)(5) the Distribution Annual Planning Report that have changed significantly from previous 2.5, 2.6, 3.1.2, 4 forecasts and information in the preceding year. S5.8(b) Forecasts for the forward planning period, including at least: See below a description of the forecasting methodology used, sources of input information, and the S5.8(b)(1) 3.2, 3.4, 3.5 assumptions applied; S5.8(b)(2) Provide load forecasts: See below S5.8(b)(2)(i) at the transmission-distribution connection points 3.3 S5.8(b)(2)(ii) for sub-transmission lines, and 3.1, 3.4 S5.8(b)(2)(iii) for zone substations 3.1, 3.2 S5.8(b)(2) Including, where applicable, for each item above: See below S5.8(b)(2)(iv)total capacity 3.1 S5.8(b)(2)(v) firm delivery capacity for summer periods and winter periods 3.1 peak load (summer or winter and an estimate of the number of hours per year that 95% S5.8(b)(2)(vi) 3.1 of peak is expected to be reached) S5.8(b)(2)(vii) power factor at time of peak load 3.1 S5.8(b)(2)(viii) load transfer capacities 3.1, 3.5.1 S5.8(b)(2)(ix) generation capacity of known embedded generating units 3.1 Provide forecasts of future transmission-distribution connection points (and any S5.8(b)(3) associated connection assets), sub-transmission lines and zone substations, including 6.1 to 6.4 for each future transmission-distribution connection point and zone substation: S5.8(b)(3)(i) its location 6.1 to 6.4 S5.8(b)(3)(ii) future loading level 6.1 to 6.4 S5.8(b)(3)(iii) proposed commissioning time (estimate of month and year) 6.1 to 6.4 forecasts of Ausgrid’s performance against any reliability targets in a service target S5.8(b)(4) 9.1.4 performance incentive scheme ; and Provide a description of any factors that may have a material impact on Ausgrid’s S5.8(b)(5) see below network , including factors affecting; S5.8(b)(5)(i)fault levels 3.6.1 S5.8(b)(5)(ii)voltage levels 3.6.2 S5.8(b)(5)(iii) other power system security requirements 3.6.3 S5.8(b)(5)(iv) the quality of supply to other Network Users (where relevant); and 3.6.4 S5.8(b)(5)(v) ageing and potentially unreliable assets 5 & 10 for all network asset retirements, and for all network asset de-ratings that would result in a system limitation, that are planned over the forward planning period, S5.8(b1) See below the following information in sufficient detail relative to the size or significance of the asset:

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Section in NER Clause NER Task Description DTAPR S5.8(b1)(1) a description of the network asset, including location; 4 & 5 the reasons, including methodologies and assumptions used by the Distribution Network Service Provider, for deciding that it is necessary or prudent for the network asset to be S5.8(b1)(2) 4 & 5 retired or de-rated, taking into account factors such as the condition of the network asset; the date from which the Distribution Network Service Provider proposes that the network S5.8(b1)(3) 4 & 5 asset will be retired or de-rated; and if the date to retire or de-rate the network asset has changed since the previous S5.8(b1)(4) 4 & 5 Distribution Annual Planning Report, an explanation of why this has occurred; S5.8(b2) for the purposes of subparagraph (b1), where two or more network assets are: See below S5.8(b2)(1) of the same type; 4 S5.8(b2)(2) to be retired or de-rated across more than one location; 4 S5.8(b2)(3) to be retired or de-rated in the same calendar year; and 4 each expected to have a replacement cost less than $200,000 (as varied by a cost S5.8(b2)(4) threshold determination), those assets can be reported together by setting out in the 4 Distribution Annual Planning Report: a description of the network assets, including a summarised description of their S5.8(b2)(5) 4 locations; the reasons, including methodologies and assumptions used by the Distribution Network Service Provider, for deciding that it is necessary or prudent for the network assets to be S5.8(b2)(6) 4 retired or de-rated, taking into account factors such as the condition of the network assets; the date from which the Distribution Network Service Provider proposes that the network S5.8(b2)(7) 4 assets will be retired or de-rated; and if the calendar year to retire or de-rate the network assets has changed since the S5.8(b2)(8) 4 previous Distribution Annual Planning Report, an explanation of why this has occurred; Information on system limitations for sub-transmission lines and zone S5.8(c) See below substations, including at least: S5.8(c)(1) estimates of the location and timing (month(s) and year) of the system limitation 3 & 5 analysis of any potential for load transfer capacity between supply points that may S5.8(c)(2) 3 & 5 decrease the impact of the system limitation or defer the requirement for investment impact of the system limitation, if any, on the capacity at transmission distribution S5.8(c)(3) 3 & 5 connection points a brief discussion of the potential solutions that may address the system limitation in the S5.8(c)(4) 3 & 5 forward planning period, if a solution is required; and where an estimated reduction in forecast load would defer a forecast system limitation S5.8(c)(5) See below for a period of, at least, 12 months, include: S5.8(c)(5)(i) an estimate the month and year in which a system limitation is forecast to occur 3 & 5 the relevant connection points at which the estimated reduction in forecast load may S5.8(c)(5)(ii) 3 & 5 occur the estimated reduction in forecast load in MW or improvements in power factor needed S5.8(c)(5)(iii) 3 & 5 to defer the forecast system limitation. for any primary distribution feeders for which Ausgrid has prepared forecasts of maximum demands under NER clause 5.13.1(d)(1)(iii) and which are currently S5.8(d) 5.26 experiencing an overload, or are forecast to experience an overload in the next two years Ausgrid must set out: S5.8(d)(1) the location of the primary distribution feeder; 5.26 the extent to which load exceeds, or is forecast to exceed, 100% (or lower utilisation S5.8(d)(2) factor, as appropriate) of the normal cyclic rating under normal conditions (in summer 5.26 periods or winter periods); S5.8(d)(3) the types of potential solutions that may address the overload or forecast overload; and 5.26 where an estimated reduction in forecast load would defer a forecast overload for a S5.8(d)(4) 5.26 period of 12 months, include: S5.8(d)(4)(i) an estimate of the month and year in which the overload is forecast to occur; 5.26 a summary of the location of relevant connection points at which the estimated S5.8(d)(4)(ii) 5.26 reduction in forecast load would defer the overload;

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Section in NER Clause NER Task Description DTAPR the estimated reduction in forecast load in MW needed to defer the forecast system S5.8(d)(4)(iii) 5.26 limitation. A high-level summary of each RIT-D project for which the regulatory investment S5.8(e) test for distribution has been completed in the preceding year or is in progress, 7.1 including: if the regulatory investment test for distribution is in progress, the current stage in the S5.8(e)(1) 7.1 process S5.8(e)(2) a brief description of the identified need 7.1 a list of credible options assessed or being assessed (to the extent reasonably S5.8(e)(3) 7.1 practicable) S5.8(e)(4) If the RIT-D has been completed, a brief description of the conclusion, including: 7.1 S5.8(e)(4)(i) the net economic benefit of each credible option 7.1 S5.8(e)(4)(ii) the estimated capital cost of the preferred option; and 7.1 the estimated construction timetable and commissioning date (where relevant) of the S5.8(e)(4)(iii) 7.1 preferred option Any impacts on Network Users, including any potential material impacts on connection S5.8(e)(5) 7.1 charges and distribution use of system charges that have been estimated. For each identified system limitation which Ausgrid has determined will require a S5.8(f) regulatory investment test for distribution , provide an estimate of the month and 7.1 year when the test is expected to commence a summary of all committed investments to be carried out within the forward planning period with an estimated capital cost of $2 million or more (as varied by S5.8(g) 7.3 & 7.4 a cost threshold determination) that are to address an urgent and unforeseen network issue as described in clause 5.17.3(a)(1), including: a brief description of the investment, including its purpose, its location, the estimated S5.8(g)(1) capital cost of the investment and an estimate of the date (month and year) the 7.3 & 7.4 investment is expected to become operational; a brief description of the alternative options considered by the Distribution Network Service Provider in deciding on the preferred investment, including an explanation of the S5.8(g)(2) ranking of these options to the committed project. Alternative options could include, but 7.3 & 7.4 are not limited to, generation options, demand side options, and options involving other distribution or transmission networks; Include the results of any joint planning undertaken with the Transmission S5.8(h) 8.1 Network Service Provider in the preceding year, including: a summary of the process and methodology used by Ausgrid and the relevant S5.8(h)(1) 8.1.1 Transmission Network Service Provider to undertake joint planning; a brief description of any investments that have been planned through this process, S5.8(h)(2) including the estimated capital costs of the investment and an estimate of the timing 8.1.2 & 8.1.3 (month and year) of the investment; and S5.8(h)(3) where additional information on the investments may be obtained. 8.1.4 Include the results of any joint planning undertaken with other Distribution S5.8(i) 8.2 Network Service Providers in the preceding year, including: a summary of the process and methodology used by the Distribution Network Service S5.8(i)(1) 8.2.1 Providers to undertake joint planning; a brief description of any investments that have been planned through this process, S5.8(i)(2) including the estimated capital cost of the investment and an estimate of the timing 8.2.2 & 8.2.3 (month and year) of the investment; and S5.8(i)(3) where additional information on the investments may be obtained. 8.2.4 Provide information on the performance of the Distribution Network Service S5.8(j) 9 Providers network, including: a summary description of the reliability measures and standards in applicable regulatory S5.8(j)(1) 9.1 instruments; a summary description of the quality of supply standards that apply, including the S5.8(j)(2) 9.2 relevant codes, standards and guidelines a summary description of the performance of the distribution network against the S5.8(j)(3) 9.1 & 9.3 reliability and quality measures and standards for the preceding year where the network reliability and quality measures and standards were not met in the S5.8(j)(4) 9.1, 9.4 & 9.5 preceding year, information on the corrective action taken or planned

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Section in NER Clause NER Task Description DTAPR a summary description of Ausgrid’s processes to ensure compliance with the measures S5.8(j)(5) 9.1 & 9.5 and standards described under subparagraphs (1) and (2) above; and an outline of the information contained Ausgrid’s most recent submission to the AER S5.8(j)(6) 9.1.3 under the service target performance incentive scheme (STPIS). S5.8(k) Include information on Ausgrid’s asset management approach, including: 10

S5.8(k)(1) a summary of any asset management strategy employed by the DNSP; 10.1 & 10.2

an explanation of how the Distribution Network Service Provider takes into account the S5.8(k)(1A) cost of distribution losses when developing and implementing its asset management 10.3 and investment strategy a summary of any issues that may impact on the system limitations identified in the S5.8(k)(2) Distribution Annual Planning Report that has been identified through carrying out asset 3.6 management information about where further information on the asset management strategy and S5.8(k)(3) 10.4 methodology adopted by Ausgrid may be obtained. S5.8(l) Include information on Ausgrid's demand management activities, including: 11 S5.8(l)(1) a qualitative summary of: See below non-network solutions that have been considered in the past year, including generation S5.8(l)(1)(i) 11.3 from embedded generating units; key issues arising from applications to connect embedded generating units received in S5.8(l)(1)(ii) 3.6.5 the past year; actions taken to promote non-network initiatives in the preceding year, including S5.8(l)(1)(iii) 11.5 generation from embedded generating units; and the DNSPs plans for demand management and generation from embedded generating S5.8(l)(iv) 11.4 units over the forward planning period (5 years for Distribution). S5.8(l)(2) a quantitative summary of: 11.6 S5.8(l)(2)(i) connection enquiries received under clause 5.3A.5; 11.6 S5.8(l)(2)(ii) applications to connect received under clause 5.3A.9; and 11.6 S5.8(l)(2)(iii) the average time taken to complete applications to connect; 11.6 Include information on Ausgrid's investments in information technology and communication systems which occurred in the preceding year, and planned S5.8(m) 12 investments in information technology and communication systems related to management of network assets in the forward planning period. Include a regional development plan consisting of a map of Ausgrid's network as S5.8(n) a whole or maps by regions in accordance with Ausgrid's planning methodology See below or as required under any regulatory obligation or requirement identifying: sub-transmission lines, zone substations and transmission-distribution connection S5.8(n)(1) 5 points; any system limitations that have been forecast to occur in the forward planning period, S5.8(n)(2) 5 including, where they have been identified overloaded primary distribution feeders.

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