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2 Table of Contents FOREWORD... 7 Document structure... 8 Certification... 9 PART A: NETWORK MANAGEMENT CORPORATE PROFILE The Power Networks business unit Operating environment Network Management Plan objectives NETWORK OVERVIEW OPERATING ENVIRONMENT AND OUTLOOK Economic outlook Climate change Stakeholder engagement NETWORK PLANNING Network Technical Code and Network Planning Criteria Development considerations Customer connections Demand forecasting Darwin Katherine demand forecast Alice Springs demand forecast Tennant Creek demand forecast System Utilisation ASSET MANAGEMENT Background Asset management policy Asset condition Maintenance categories Asset management processes Asset management systems End of life management Strategic asset plans Page i

3 5.9 Asset replacement CUSTOMER STANDARDS OF SERVICE Introduction Network reliability Transmission network performance against targets Distribution network performance against targets Network performance indicators Yearly SAIDI and SAIFI trends by feeder category Poorly performing feeders Service quality Low voltage quality BUSINESS PERFORMANCE IN 2013/ Capital program Maintenance program PART B: NETWORK DEVELOPMENT TRANSMISSION AND ZONE SUBSTATION DEVELOPMENT Network Development Strategies year master plan Forecast capital program Major capital projects Minor Capital Programs for Asset Replacement APPENDIX APPENDIX APPENDIX APPENDIX APPENDIX Page ii

4 Table of Figures Figure 1 - Power Networks organisational structure Figure 2 - Regulated electricity networks Figure 3 - Northern Territory building approvals Figure 4 - Northern Territory population growth Figure 5 - Trend in Gross State Product, Northern Territory Figure 6 Wishart 66/11kV Modular Substation Figure 7 - PV Installed Capacity, Darwin Katherine Region Figure 8 - Number of new and upgraded customer connections Figure 9 - Spatial demand forecasting process Figure 10 - Load factor, Darwin Katherine System Figure 11 - Load duration curves, Darwin Katherine System Figure 12 - Wet season day demand vs maximum daily temperature, Darwin Katherine System Figure 13 - Wet season maximum daily temperature distribution, Darwin Katherine Figure 14 - GSP based SWMD forecast, Darwin Katherine System Figure 15 - PV adjusted, GSP based SWMD forecast, Darwin - Katherine System Figure 16 - Spatial SWMD Forecast, Darwin Katherine System Figure 17 - System Demand Forecast, Darwin Katherine System Figure 18 - Load factor, Alice Springs Figure 19 - Load duration, Alice Springs Figure 20 - Summer day demand vs maximum daily temperature, Alice Springs Figure 21 - Summer maximum daily temperature distribution, Alice Springs Figure 22 - Spatial SWMD Forecast, Alice Springs System Figure 23 - PV adjusted SWMD forecast, Alice Springs System Figure 24 - System Demand Forecast, Alice Springs System Figure 25 - Load factor, Tennant Creek System Figure 26 - Load duration, Tennant Creek System Figure 27 - Summer maximum daily temperature distribution, Tennant Creek System Page iii

5 Figure 28 - System Demand Forecast, Tennant Creek System Figure /14 Transmission terminal station and zone substation utilisation Figure 30-11kV feeder utilisation Figure 31-22kV feeder utilisation Figure 32 - Age profile of transmission terminal station and zone substation equipment Figure 33 - Age profile of distribution substations Figure 34 - Asset Maintenance Cycle Figure 35 - Capital Expenditure Process Figure 36 - Darwin Monthly Vegetation SAIDI and Darwin Monthly Rainfall Figure Transmission FCO cause breakdown Figure Transmission FTO cause breakdown Figure CBD SAIDI and SAIFI causes Figure Urban SAIDI and SAIFI causes Figure Rural Short SAIDI and SAIFI causes Figure Rural Long SAIDI and SAIFI causes Figure 43 - Accumulated CBD adjusted SAIDI trends Figure 44 - Accumulated CBD adjusted SAIFI trends Figure 45 - Accumulated Urban adjusted SAIDI trends Figure 46 - Accumulated Urban adjusted SAIFI trends Figure 47 - Accumulated Rural Short adjusted SAIFI trends Figure 48 - Accumulated Rural Short adjusted SAIDI trends Figure 49 - Accumulated Rural Long adjusted SAIDI trends Figure 50 - Accumulated Rural Long adjusted SAIFI trends Figure 51 - RMS voltage distribution histogram for commercial & residential connections Figure 52 New Manton 22kV Indoor Switchroom Figure 53 - Preventative Maintenance completion against target ( ) Page iv

6 Table of Tables Table 1 - Power Networks statistics (regulated network) Table 2 - Gross State Product Table 3 - Definition of load types Table 4 - Radial supply restoration targets Table 5 - Supply contingency criteria - CBD and Urban areas Table 6 - Supply contingency criteria - Non-urban and Remote areas Table 7 - PV Policy Class Summary Table 8 - MD Offset Factors Table 9 - Forecast Reconciliation Darwin Katherine System Table 10 - Darwin-Katherine transmission performance indicators Table 11 - Alice Springs transmission performance indicators Table 12 - Distribution SAIDI results segmented by feeder category (adjusted) Table 13 - Distribution SAIFI results segmented by feeder category (adjusted) Table 14 - Unadjusted power system transmission performance Table 15 - Power system transmission SAIDI and SAIFI Table Distribution unadjusted SAIDI by feeder category and region Table Distribution unadjusted SAIFI by feeder category and region Table Distribution adjusted SAIDI by feeder category and region Table Distribution adjusted SAIFI by feeder category and region Table Unadjusted SAIDI and SAIFI by feeder category Table SAIDI by region Table SAIFI by region Table 23 - SAIDI threshold for poorly performing feeders by feeder category Table 24 - Customer notifications relating to quality of supply Table 25 - Number of customer complaints Table 26 - Average time taken to respond to a customer s written enquiry segmented into regions Table 27 - Percentage and total number of new and re-connections not undertaken Page v

7 Table 28 - Number and average length of time taken to provide new connections in urban areas Table /14 Maintenance expenditure by maintenance type Regulated Network and Standard Control Services Table 30 Forecast capital expenditure Page vi

8 FOREWORD Power and Water Corporation (Power and Water) is a government owned corporation responsible for the transmission and distribution of electricity in the Northern Territory. Power and Water s electricity transmission and distribution activities are regulated under the Electricity Networks (Third Party Access) Act by the Utilities Commission (Commission), which is responsible for setting customer service levels, approving prices and access conditions, and reviewing Power and Water s performance. Section 9 of the Electricity Networks (Third Party Access) Code, set out in the Electricity Networks (Third Party Access) Act, requires Power and Water to comply with good electricity industry practice when providing network access services and in planning, operating, maintaining, developing and extending the electricity network. It also requires Power and Water to publish and maintain a Network Technical Code and Network Planning Criteria. As part of its annual performance monitoring and review cycle, the Commission requests information from Power and Water in order to make determinations regarding the adequacy of demand forecasts, transmission and distribution network plans, asset management practices and customer service levels. The Network Management Plan (Plan) is not directly required to meet Power and Water s existing legislative or regulatory obligations. Rather, it is an initiative designed to explain the Corporation s intentions for the next five years in relation to network reliability, capacity, security and supply quality and the accompanying development of the network. It is based on similar plans developed by distribution network service providers in other jurisdictions and adapted to Power and Water s circumstances. The Plan will provide Power and Water s stakeholders with an insight into the important challenges Power Networks faces and how Power Networks will respond. The Plan will also increase the transparency of the electricity network s management and operation, by providing: information on Power Networks management practices; much of the Commission s routine information requirements; and information on the proposed development of the network, over the next five years and beyond. The publication of planning information is designed to further facilitate the development of non-network alternatives to traditional network expansion. This Plan is updated annually and will be available on Power and Water s website. Page 7 of 110

9 Document structure This document has been arranged in two substantive parts: Part A: Network Management this part of the Network Management Plan provides information on network performance and capacity, along with background and contextual information, including details of asset management policies and strategies. Part B: Network Development this part of the Network Management Plan provides detailed information regarding the capability and development planning of Power and Water s electricity supply network. Part B is also intended to facilitate a process of public consultation and stakeholder feedback on network constraints, supply issues and proposed solutions and thereby provide awareness of potential investment opportunities which may be cost effective in avoiding, or postponing network expansion. Page 8 of 110

10 Certification We, the undersigned, hereby certify that: this Plan is consistent with Power and Water s obligations under the relevant legislation; the Plan accurately represents the relevant policies of Power and Water; Power and Water has complied with those policies and/or provides details of where it has not complied herein; and Power and Water is committed to implementing this Plan. John Baskerville Chief Executive Power and Water Corporation John Greenwood General Manager Power Networks Power and Water Corporation Page 9 of 110

11 PART A: NETWORK MANAGEMENT Part A of the Network Management Plan (Plan) provides information on network performance and capacity, along with background and contextual information, including details of asset management policies and strategies. 1. CORPORATE PROFILE Power and Water is responsible for electricity transmission and distribution services and provides water and sewerage services across the Northern Territory, an area of more than 1.3 million square kilometres. Power and Water also supplies electricity generation and retail services to 72 remote communities through its not-for-profit subsidiary, Indigenous Essential Services Pty Ltd. Power and Water became the Northern Territory s first government owned corporation under the Government Owned Corporations Act on 1 July In accordance with the Act, Power and Water s objectives are to: operate at least as efficiently as any comparable business; and maximise the sustainable return to the Northern Territory on its investment in Power and Water. Power and Water aspires to be a leading utility business, valued and respected in its community. Power and Water is working to be commercially sustainable, meet service standards and maintain a professional, capable and accountable workforce within a positive and safe environment. Page 10 of 110

12 1.1 The Power Networks business unit Power Networks is a ring-fenced electricity transmission and distribution business within Power and Water that has responsibility for planning, building and maintaining reliable electricity networks to transport electricity between electricity generators and electricity consumers in the Northern Territory. Its mission is to achieve this in a safe, reliable, efficient and environmentally sustainable manner. The organisational structure of the Power Networks business unit is presented in Figure 1 - Power Networks organisational structure. General Manager Power Networks Strategy & Planning Service Delivery Southern Network Health & Safety Commercial Operating groups Divisional support groups Figure 1 - Power Networks organisational structure Power Networks has separated its responsibilities into two major streams. Planning and engineering activities are undertaken by the Strategy and Planning Group and delivery activities are undertaken by the Service Delivery Group. The Southern Network Group undertakes both planning and engineering activities (Strategy and Planning), and delivery (Service Delivery) activities to the Alice Springs network. The divisional support groups, such as Commercial and Health and Safety, provide support to the operational groups within Power Networks. Power Networks regulated assets are valued at $928.3 million as at 1 July and there was 5 701km of overhead line and 2 971km of underground cable in the regulated network as at 30 June Opening asset value as at 1 July 2014 Utilities Commission, 2014 Network Price Determination, Final Determination, PWC Power Networks NT Revenue Model.. Power Networks Annual Licence Return, as submitted to the Utilities Commission. Page 11 of 110

13 1.2 Operating environment Power Networks operates under a Network Licence issued by the Commission which authorises it to: own and operate an electricity network within the geographic area specified in Schedule 2 of that Network Licence, as set out below; and connect the electricity network to another electricity network, in accordance with the terms and conditions of the Network Licence. Schedule 2 of the Network Licence lists the regulated electricity network(s) covered by the Licence: Darwin (city, suburbs and surrounding rural areas); Katherine (township and surrounding rural areas); Darwin-Katherine Transmission Line (132kV) that extends from the network 132kV bus at Channel Island Power Station to a 132/22kV substation adjacent to the Katherine Power Station, with a 132/22kV substation at Manton and a 132/66kV substation at Pine Creek; Tennant Creek (township and surrounding rural areas); and Alice Springs (township and surrounding rural areas). Power Networks also provides electricity network services to the unregulated areas of the Northern Territory. However, the focus of the Network Management Plan is on the regulated areas covered by Power Networks Network Licence Legislation Power and Water s legislative environment circumscribes its scope of activities, specifies its statutory obligations and confers the regulatory powers of the Commission. The four main legislative acts, which together provide the legal foundation for Power Networks statutory obligations, are as follows: Power and Water Corporation Act; Utilities Commission Act; Electricity Reform Act; and Electricity Networks (Third Party) Access Act. Power and Water, and its service providers, are also subject to numerous other environmental, cultural heritage, planning approval, workplace health and safety, financial and other regulatory obligations or requirements under a range of federal, Territory and local government legislation, codes, standards, policies and other instruments. Page 12 of 110

14 1.2.2 Network regulation The Commission is responsible for regulating the technical and commercial aspects of Power and Water s regulated network service business under the Northern Territory s legislative framework. The Standards of Service Code is the key instrument used by the Commission to regulate the minimum standards for network reliability, power quality and customer service. The Standards of Service Code specifies the following key standards of service performance measures for network services, which Power and Water must report against on an annual basis: network reliability; feeder reliability; power quality; and customer service. The Commission also established a Guaranteed Service Level Scheme to apply to customers consuming less than 160 megawatt hours per annum connected to the regulated network. The Guaranteed Service Level Code sets out the arrangements for payments to be made by network providers to small customers (<160 MWh per annum) who receive poor levels of service. The Commission s annual Power System Review reports on power system performance and capacity in the Northern Territory. The Review provides information and analysis of historical and forecast power system performance, focusing on the previous financial year and trends over the last five years and on the upcoming ten years Financial Prices paid by network users for the conveyance of electricity through regulated electricity networks in the Northern Territory are set under the Electricity Networks (Third Party Access) Code. The Electricity Networks (Third Party Access) Code requires the Commission, in consultation with interested parties, to review and subsequently determine the network price regulation methodology to be used to set regulated electricity network prices every five years (termed a regulatory control period). The Page 13 of 110

15 Commission approves, on an annual basis, the Standard Control Network Tariffs charges to apply within each regulatory control period. Power Networks is currently subject to the Commission s 2014/15 to 2018/19 Network Price Determination (2014 NPD) 3. Standard Control Network Tariffs were developed for the 2014/15 financial year in accordance with the Commission s 2014 NPD Final Determination. In addition to the standard control service charges, there are a range of Alternative Control Service charges that provide transparency and certainty for customers in terms of the charges able to be applied by Power Networks. Further information on the 2014/15 tariffs and charges and future price trends can be found on Power and Water s website Network Management Plan objectives This Plan s key objectives are to: provide stakeholders with greater transparency of the electricity network s management and operation by documenting Power Networks mission, the major challenges and management strategies and plans; satisfy much of the Commission s reporting requirements for the regulated electricity network; lay the foundation for subsequent regulatory price determinations; provide a framework for continuously improving the network s technical and economic performance; and disseminate information on the proposed development of the network over the next five years and beyond, thereby facilitating the development of non-network alternatives to traditional network expansion. The Plan s objectives are explained in more detail in sections to Delivering a safe, reliable and efficient network Power Networks mission is to safely, reliably and efficiently transmit and distribute electricity to meet the needs of customers in the Northern Territory, while 3 4 Utilities Commission, 2014 Network Price Determination: Final Determination April Page 14 of 110

16 controlling costs to minimise consumer prices and having regard to environmental management. This is consistent with the Government Owned Corporations Act objectives: to operate at least as efficiently as any comparable business; and to maximise the sustainable return to the Northern Territory on its investment in the Corporation. The Plan outlines the company s key strategies, plans and performance with respect to network reliability and the delivery of an efficient, least cost network service Basis for regulatory proposal (for Network Price Determination) Power Networks is required to submit detailed network development, operation and maintenance plans and budgets every five years as part of its Regulatory Proposal for the Network Price Determination process. This Plan provides the framework for ensuring that Power Networks has robust future plans and associated justification for Networks Price Determinations Framework for continuous improvement The Plan supports good industry practice by providing a framework for assuring the quality and continuous improvement of Power Networks network development and management processes, strategies and performance. The Plan provides quality assurance by documenting the key performance measures against which network performance will be measured, the processes by which the organisation plans to achieve these measures, the strategies and plans developed as a result of the process and the actual performance of the network against the measures. As part of the annual update process, the Plan reports on the network s actual performance against targeted performance. Any identified under-performance or non-conformance is documented as part of this process, along with management s strategies for addressing it. The Plan supports continuous improvement by providing a feedback loop to management and stakeholders regarding the effectiveness of management strategies and plans in delivering targeted network performance and cost, and by documenting new management strategies aimed at improving performance at regulated cost, or maintaining performance at lower cost. Power Networks continuous improvement process ensures that efficiency gains are systematically identified and implemented. Page 15 of 110

17 1.3.4 Network development Part B of this Plan provides details of the planned network development over the next five years (or over a longer duration, in some instances). The intent of providing this information is twofold: to demonstrate to stakeholders the process by which the network is progressively developed to maintain acceptable security, reliability and quality of supply, whilst catering for new load and generator connections and generally increasing electrical demand; and to signal to potential providers where opportunities may exist for the economic development of non-network solutions to maintain acceptable standards of supply. Non-network solutions may be developed by third parties and include, without limitation, embedded generation, demand management, power factor correction and contracted load reductions with customers. Page 16 of 110

18 2 NETWORK OVERVIEW Power and Water operates three separate regulated electricity supply systems within the Northern Territory, as illustrated in Figure 2. Figure 2 - Regulated electricity networks These three regulated electricity supply systems are: the Darwin Katherine system, the largest system and supplies the city, suburbs and surrounding areas of Darwin, the township of Katherine and its surrounding rural areas. The Darwin Katherine 132kV line links these two centres with intermediate 132kV substations at Manton and Pine Creek. There are power stations located at Channel Island, Weddell, Pine Creek and Katherine; the Tennant Creek system that supplies the township of Tennant Creek and surrounding rural areas from its centrally located power station; and the Alice Springs system that supplies its township and surrounding rural areas, from the Ron Goodin Power Station and the Owen Springs Power Station. The three respective systems are abbreviated as D-K, TC and AS in this Plan. Page 17 of 110

19 Power and Water s electrical networks operate at transmission voltages of 132kV and 66kV and high voltage reticulation at 22kV and 11kV. The majority of the Northern Territory, except for the Darwin and Alice Springs townships, has a very low customer density. Power and Water operates in diverse climates, each of which brings with it unique challenges such as cyclones and tropical storms in the north, and dust storms and drought in Central Australia. In addition, high termite activity occurs throughout the Northern Territory, which dictates the use of steel and concrete power poles. These geographic and environmental variations influence the design criteria for infrastructure as well as Power Networks ability to respond to incidents on the transmission and distribution systems. The low load density and geographical spread impact on network topography, with much of the transmission and distribution network being characterised by long radial lines. The three major Power and Water electrical systems are not connected to the national grid and operate as separate stand-alone systems. The table below contains descriptive statistics for the regulated electricity networks. Table 1 - Power Networks statistics (regulated network) Power Network Statistic As at 30 June 2014 Regulated System D-K TC AS Energy delivered (GWh) Actual Maximum Demand (MW) Number of Transmission Terminal Stations 4 Number of Zone Substations 24 Number of Distribution Substations 4503 Number of Major Power Transformers (22kV to 132kV) Transmission overhead (132kV and 66kV) Transmission underground (66kV) High Voltage overhead (22kV, 11kV and SWER) High Voltage underground (22kV and 11 kv) Low Voltage overhead (includes service mains and streetlights) Low Voltage underground (includes service mains and streetlights) 58 (excludes generator and spare transformers) 721 km 39 km km 759 km km km Page 18 of 110

20 3 OPERATING ENVIRONMENT AND OUTLOOK The electrical demand on the network is related to growth in the number of and the peak demand of individual customer connections. The population and economic growth taking place in the Northern Territory in turn drives these factors. 3.1 Economic outlook The following discussion concerns trends in the economic indicators that underpin the growth in demand on Power and Water s networks. The first of these indicators is the historic Northern Territory building approvals, illustrated in Figure 3. Figure 3 - Northern Territory building approvals The monthly trend in building approvals is shown with the five-year rolling average superimposed. Historically there is an annual and cyclical variation evident in the approvals trend in Figure 3, however in recent years the cyclic variation has lifted increasing the rolling five-year average from approximately 100 dwellings per month to over 120 dwellings per month. The immediate and medium term economic outlook for the Northern Territory remains higher than average and higher than national levels. This increased economic activity, including an increased demand in dwellings flows through to above average demand for electricity and increased numbers of connections to the network. Page 19 of 110

21 The trend in building approvals is supported by the growth in population in the Northern Territory. In this regard, the previous and most recent population forecasts by the Australian Bureau of Statistics (ABS), as well as the most recent Northern Territory Treasury population forecasts are shown in Figure 4. Population forecasts from the ABS have been adjusted with the recent census data. The result shows a tighter grouping between the three different growth scenarios and more in line with the Northern Territory Treasury figures 5. As at March 2014 the annual population growth for the Territory is 1.4 per cent, above that of South Australia and Tasmania and below the Australian average of 1.7per cent 6. This steady population growth is slightly below recent historical population growth 7 so this data generally supports underlying electricity demand growth remaining at existing levels or lower in the medium to long term. Figure 4 - Northern Territory population growth The economic activity in the Northern Territory is customarily measured by the Gross State Product (GSP). In recent years the Territory s economy has been 5 Table 7.1, Budget Paper No2, Budget Strategy and Outlook , 9 May Ref: 31010DO001_ Australian Demographic Statistics, Mar Ref: 31010DO001_ Australian Demographic Statistics, Mar 2014 Page 20 of 110

22 experiencing high growth relative to all other states and above Australia s Gross Domestic Product (GDP) largely driven by private investment, household consumption and net exports 8. As a consequence the power system demand has also been subjected to strong growth drivers. The Territory Budget Strategy and Outlook 9 notes that the economic outlook remains strong for the short term; The Territory economy is expected to grow strongly over the budget and forward estimates period. Growth over the next two years is expected to be primarily supported by construction activity related to the Ichthys project, which is expected to have a positive flow-through impact on other industries. However in the medium term the outlook appears to slow or transitional; From , the Territory economy is forecast to undergo a significant transition, with economic growth expected to be underpinned by a substantial increase in net exports as the Ichthys project moves towards the production phase. Accordingly, transition is also apparent in the expected Gross State Product figures as shown in the table below that fall away from the peak in 2014/15. The projected 2017/18 GSP figure of 3.5 per cent being close to the long term GSP average of 3.3 per cent, showing a return to average growth in the medium term. Table 2 - Gross State Product e f f f f Gross state product Figure 5 shows the actual historic GSP growth, the five year rolling average, as well as the long term 22 year average 10. The shaded area indicates one standard deviation from this average. Projections to 2018 are sourced from the Northern Territory Treasury figures as shown above in Table 2. 8 Territory Economic Review, (I-TER1410-I04), October Chapter 7, Budget Paper No2, Budget Strategy and Outlook , 9 May Australian Bureau of Statistics, S Australian National Accounts: State Accounts, Series ID A K Page 21 of 110

23 Figure 5 - Trend in Gross State Product, Northern Territory Historical growth can be a reasonable indicator of future growth providing that the external drivers and behaviours remain constant. Unfortunately this is rarely the case and reliance on historical trends alone is unlikely to provide an accurate forecast. While the GSP provides some indication as to future growth, influences such as changing behaviour, changing demography, varying economic streams and new technology all may affect the validity of extending a correlation into the future Correlation of demand with economic growth It is interesting to note that the short term historical correlation between GSP and electricity consumption and demand is very high in the Darwin Katherine region. Analysis of the GSP and historical Standard Weather Maximum Demand (SWMD) since 2006 shows a linear correlation between these two variables, with a reasonably high coefficient of determination of Using the NT Treasury forecast GSP figures and the long term GSP average, a GSP based SWMD forecast can be developed. Such a forecast is developed and discussed in Climate change Climate change sets the scene for an increasingly challenging environment for Power Networks. The main impacts on the network are expected to arise from: the increasing summer/wet season temperature and the increase in the number of hot days will cause disproportionate increases in network demand; the capacity of most items of network equipment to supply that demand is dependent upon the ambient temperature and will be adversely affected; increased monsoonal rainfall across the north of the Northern Territory will narrow the dry season window of opportunity, during which major equipment maintenance must be performed ; and Page 22 of 110

24 increased rainfall in central areas will increase the incidence of flooding, causing equipment damage and impairing access. 3.3 Stakeholder engagement Power and Water actively engages with government departments, developers and industry groups Government engagement The Power Networks business unit actively engages with many government agencies across a broad range of activities to ensure business plans and objectives are cognisant of the broader operating environment and also in achieving short term operational outcomes. Power Networks participates in a number of the Northern Territory Governments (NTG) Project Control Groups to discuss future development plans across the Territory and the impact these developments will have on existing infrastructure as well as highlighting areas in advance, where additional services are required. A close relationship also exists between other government (and non-government) infrastructure departments or businesses to ensure that the ongoing operational needs of the power network are maintained as infrastructure is developed and routine operational requirements are updated. Such interactions are common place between road and rail operators, local councils and environmental departments Developer engagement Power Networks are closely involved with all scales of building development, from individual lots, through to entire new sub-divisions and townships. Engagement includes NTG agencies such as Lands Development Corporation and the Department of Lands, Planning and Environment as well as with numerous private developers on specific project requirements. Engagement ensures that the power head-works are in place, all new assets are designed and installed to the required standards for successful long term operation, that Power Networks interests are protected in regards to easements and access and any required capital contributions are understood and paid appropriately. The engagement is also an opportunity for Power Networks to receive feedback towards improving business process. For example, with developer feedback Power Networks is better able to understand works within the planning horizon and more accurately forecast future developments and likely loads. It is also an opportunity to review asset standards and design practices to ensure they are current and meeting the needs of all stakeholders. Page 23 of 110

25 3.3.3 Industry group engagement Membership and engagement with peak industry bodies and industry peers is paramount in order for Power Networks to remain aware of the latest industry practices as well as developing industry trends. These issues drive improvement in every aspect of the Power Networks business from maintenance improvement, changes to customer behaviours for planning, use of modern equipment in testing and operations through to changes in electricity market trends and so on. Page 24 of 110

26 4 NETWORK PLANNING Network planning is based around a design philosophy that reinforces the network in order to meet demand growth and allow for continued supply in the event of specified contingencies. 4.1 Network Technical Code and Network Planning Criteria The Network Technical Code and Network Planning Criteria set out the supply contingency criteria used to plan Power and Water s network. Supply contingency criteria relate to the ability of the supply system (network and generation) to be reconfigured after a fault, so that the supply to customers is restored. The criteria apply to generation used to support the network and to the network interconnections to generators. For completeness the relevant provisions of the Network Planning Criteria have been repeated in this section. The load areas identified for the purpose of the supply contingency criteria are set out in Table 3. Table 3 - Definition of load types Load type CBD Urban Non-urban Remote Definition Any area within a city or town that is zoned as Central Business District (CBD) in the Northern Territory Planning Scheme. An area in which the majority of the land is zoned for residential and/or commercial and/or industrial use within a major centre in the Northern Territory and is not CBD. Areas that are not urban and not within a CBD but which are within a 50km radius of a CBD. Areas outside a 50km radius from a CBD Supply contingencies A single supply contingency (first contingency) may involve the unplanned failure of an element of network equipment (a cable, line or transformer), or the failure of a generator used to support the network or supply loads at a particular location. A second supply contingency involves the concurrent failure of two elements, which could comprise network equipment or generators. In addition, at the discretion of Power Networks, certain high impact but low risk failures such as the failure of a single zone substation High Voltage (HV) busbar, or the failure of both circuits of a double circuit line, shall be considered as second contingency events. Page 25 of 110

27 4.1.2 Equipment capacities Circuit capacities used in determining supply adequacy are the appropriate cyclic ratings for network equipment. Work is ongoing in this area to confirm and manage the equipment capacities under various operational conditions Forecast demand The forecast area demand used for determining supply adequacy is the coincident maximum demand for the load area, feeder or transformer concerned, with a 50 per cent probability of exceedence. In radially supplied areas the forecast is considered with a 10 per cent probability of exceedence Radial supply arrangements Where restoration of supply requires reinstatement or repair, a secure supply having an alternative path is not provided. Restoration targets are set out in Table 4. Table 4 - Radial supply restoration targets Radial supply contingency For failure of a substation transformer For failure of a subtransmission line For failure of a subtransmission line Restoration target 36 hours 6 hours (loads greater than 5MVA) 12 hours (loads less than 5MVA) The restoration times in Table 4 are Power Networks internal targets. They do not represent customer guarantees. Actual restoration times are based on ensuring staff safety and being able to access and address the asset related issues Supply contingency criteria The supply contingency criteria in the Network Planning Criteria have been designed to facilitate Power Networks providing the specified response in the most appropriate and economical manner for the particular circumstances. The response to ensuring the supply contingency criteria are met may include one or more of: augmentation of the network; reduction of demand on the network using demand management; connection of generation within the load area concerned; commercial arrangements with generators to provide demand support in contingency conditions; enhanced operational response; enhanced control of network configuration; and contingency planning using strategically positioned spare equipment or mobile equipment such as generators and transformers. Page 26 of 110

28 The supply contingency criteria apply to loads and to groups of loads supplied by the network at various voltage levels and locations. In determining the relevant supply contingencies to loads and groups of loads, the potential unavailability of: elements of the network that normally supply those loads; the generators that normally supply those loads; and the associated generator connections are all considered. The relative likelihood of supply contingencies is also considered. In addition, Power Networks aims to meet reliability of supply objectives established by benchmarked industry practice. Where the availability of generation is a factor in meeting the contingency criteria in a particular load area, Power Networks will consult with the relevant generators to make appropriate allowance for generation unit maintenance. Power Networks may enter into commercial arrangements with a generator to provide demand support in supply contingency conditions. The Planning Criteria in Table 5 apply for the specified supply contingencies in CBD and Urban areas. The Planning Criteria in Table 6 apply for Non-urban and Remote areas. Page 27 of 110

29 Table 5 - Supply contingency criteria - CBD and Urban areas Class of supply Forecast area demand A Up to 1MVA Within 8 hours: area demand B C D Over 1MVA and up to 5MVA Over 5MVA and up to 50MVA Over 50MVA Minimum demand to be met after: First supply Second supply contingency contingency No special provision (a) Within 3 hours: area demand less 1 MVA (b) Within 8 hours: area demand (a) Within 60 minutes: area demand (a) Immediate restoration area demand of (b) Within time to restore planned outage: area demand (c) Within 5 hours: area demand Notes Area demand is normally supplied from one source. Restoration of supply requires reinstatement or repair. Includes most HV customer connections and distribution substations. Where a single transformer supplies demand, the area demand may cover the transformer cyclic capacity. Area demand is normally supplied from one source and may have partial to full supply available from an alternative source. Includes most HV feeders, allows for manual field switching. Area demand is normally supplied from one or more source and will have partial to full supply from an alternative source. Will include many HV feeders and all zone substations. Area demand will be restored with automatic or manual switching of alternative sources of supply. Area demand will normally be supplied by more than two alternative circuits with high level automatic and supervisory switching. The time permitted for restoration of supply to the Darwin CBD following a second contingency recognises that manual switching of load on the CBD HV network would be necessary. The second contingency provision is not intended to restrict the period during which maintenance can be scheduled. The provision for a second circuit outage assumes that normal maintenance would be undertaken when demand is less than peak. Page 28 of 110

30 Table 6 - Supply contingency criteria - Non-urban and Remote areas Class of supply Forecast area demand Minimum demand to be met after: First supply contingency E Up to 1MVA Within 12 hours: area demand F G H Over 1MVA and up to 5MVA Over 5MVA and up to 15MVA Over 15MVA and up to 50MVA (a) Within 6 hours: area demand less 1MVA (b) Within 12 hours: area demand (a) Within 3 hours: area demand (b) Within 36 hours: area demand (a) Within 30 minutes: area demand (b) Within 36 hours: area demand Second contingency No special provision supply Notes Area demand is normally supplied from one source. Restoration of supply requires reinstatement or repair. Includes most rural spur connections, HV customer connections and distribution substations. Where a single transformer supplies demand, the area demand may cover the transformer cyclic capacity. Area demand is normally supplied from one source and will have partial to full supply available from an alternative source. Full restoration of supply may require reinstatement or repair. Includes most HV feeders, allows for manual field switching. Area demand is normally supplied from more than one source and will have full supply from an alternative source. Includes many zone substations. Area demand will be restored with manual switching of alternative sources of supply. Where area demand supplied from a single source (b) will apply. Area demand is normally supplied from more than one source and will have full supply from an alternative source. Will cover larger zone substations. Area demand will be restored with automatic or remote manual switching of alternative sources of supply. Where area demand supplied from a single source (b) will apply. Page 29 of 110

31 4.2 Development considerations Forecast peak demand growth Power Networks identifies the underlying growth in electricity demand for each zone substation and feeder based on the Demand Forecasting Procedure identified in section 4.4 and includes: the analysis and extrapolation of historic trends; known factors such as new loads above 1MVA; customer trends such as the increase of air-conditioning; and general population growth. At the system and zone substation levels, a process of temperature correction of demand to improve the robustness of demand forecasts is applied. The forecast peak demand result for each site is reviewed in consideration of the area demand growth, contingency supply arrangements as well as the system master plan. Any areas of concern are to be further investigated and may be the major driver for the development of options for capital investment on the network or another non-network solution such as alternative generation arrangements or demand management schemes. Figure 6 Wishart 66/11kV Modular Substation Page 30 of 110

32 4.2.2 Interaction with generation Planning for the development of the network will only yield least-cost outcomes if the interaction between generation costs and transmission costs is optimised. The cost of augmenting the network to relieve a constraint that results in out-of-merit generation needs to be weighed against the marginal cost of the out-of-merit generator Demand management The main areas identified by Power Networks for demand management include: tariff structures; load shifting; power factor correction; and embedded generation and network support Tariff structures A number of network tariff structural changes are under consideration by Power Networks for possible implementation during the regulatory control period: a progressive change from the existing declining block to an inclining block structure for domestic and commercial customers equipped with accumulation meters; the adoption of voltage based tariffs for customers with an annual consumption in excess of 750 MWh, accompanied by removal of the declining block energy and demand tariff structures; and the adoption of an excess kvar charge, for reactive power consumption in excess of the limits set out in the revised Network Technical Code Load shifting Improvement of the system load factor by load shifting produces significant benefits in terms of optimum loading of generators, minimising losses and deferring capital investment. Discussions with large customers with the ability to shift their load are continuing to determine appropriate communications strategies Power factor correction Power Networks has instigated four projects in the Darwin-Katherine grid and two in Alice Springs to install static capacitor banks for system security (voltage recovery) and reactive power support in zone substations. Improvement in system power factor is also of immediate importance, as the transmission of reactive power is the cause of unnecessary losses in the network and voltage regulation problems. Consumers can install power factor correction equipment, with a modest payback period if the right pricing signals are available. Power and Water has regular discussions relating to power factor with its major Page 31 of 110

33 consumers. Benefits accrue to both the customer and Power Networks. Within the consumer s installation there can be reduced losses, better voltage regulation and potentially better utilisation of equipment capacity. The kvar tariff initiative outlined above will assist in providing more appropriate price signals Embedded generation Power and Water continues to investigate if there is other capacity that might be available from commercial customers with standby generation in the Darwin - Katherine network. Power and Water is currently developing guidelines for the operations of standby generation in parallel with the grid. This work is based on national guidelines established by the Energy Networks Association. It is estimated there is approximately 30 MW of standby generation in the Darwin-Katherine region. Access to this generation could be potentially helpful in times of a network constraint. In recent years a small number of embedded generators have connected to the distribution network. For the most part this arrangement has been a co-generation arrangement in order to offset the internal electrical loads rather than to commercially export power. Recent changes to the Power Networks Photovoltaic Policy considers all systems above 30 KVA as embedded generators Photovoltaic systems Photovoltaic Policy In July 2012, following system technical analysis and broad internal consultation Power Networks began to apply a standard approach to Photovoltaic (PV) applications for the regulated network and implemented the first supporting PV policy by September The policy s main feature was a 4.5kW pre-approved application pathway. This pathway permits single phase PV systems of 4.5kW or smaller to be installed with standard paperwork and without specific engineering review and approval. This pathway has been win win in that the application process is less of a burden on Power Network resources and it is also faster and easier for installers and customers to progress installations. Since this policy was established, photovoltaic technology has evolved considerably and PWC (as well as broader utility industry) experience has also increased considerably over this time. As such, it was prudent to revise the PV policy. The revised PV policy has resulted in the formalisation of previous practices such as the direct approval of three phase 6kW PV systems and a firm limit on domestic/residential PV system sizes. The revised policy also includes a broader preapproved pathway based on the utilisation of export limiting technology. In addition to these features the application process has been divided into four classes that are reflective of the system size and the complexity required in the assessment and approval. These classes also align to industry practice, relevant Australian Standards and existing PWC documentation. Cost reflective charges are Page 32 of 110

34 now implemented for engineering studies. Table 7 summarising the revised PV policy follows. Table 7 - PV Policy Class Summary Class Applicants Darwin Region Alice Springs Katherine Tennant Creek Comments Class 1 Private / Residential 4.5 kw* single phase OR 6 kw* three phase Pre-approved *Sized by PV Panel Array (DC) Class 2 Small commercial 30 kva three phase with zero export limiter Pre-approved Sized by inverter (AC) Class 3 Medium commercial 200 kva three phase 100 kva three phase Requires Assessment Sized by inverter(ac) Class 4 Large commercial > 200 kva three phase > 100 kva three phase Requires Assessment Sized by inverter (AC) Photovoltaic Systems Residential PV system uptake is rapidly increasing. The following Figure 7 shows the installed capacity increase over recent years (blue) and a projected uptake into the future (green). The future PV forecast for the Darwin Katherine system has been based on a scaled forecast from the Power System Review 11. The original forecast is also shown (red) for reference. Some causational extrapolation of data has been required between regions in previous years and data does not include independent power producers. 11 Table 4.6, p70, Power System Review , June Page 33 of 110

35 Figure 7 - PV Installed Capacity, Darwin Katherine Region The expected forecast increase in PV has been determined in both the Darwin Katherine and the Alice Springs regions and subsequently applied to adjust the standard weather maximum demand forecasts as discussed in the demand forecasting section of this document. The maximum demand influence of each PV installation has been adjusted by the Maximum Demand (MD) offset factor. This factor allows for coincident solar generation and system demand to determine the highest likely reduction in maximum demand due to installed PV. The MD offset factors are as follows 12 : Table 8 - MD Offset Factors Darwin Katherine Alice Springs Table 4.5, p69, Power System Review , June Page 34 of 110

36 4.2.5 Network modernisation Asset renewal The majority of the 1960/70s vintage equipment on the network is being replaced with modern equipment, using different technologies. Oil filled switchgear with its attendant high risk of catastrophic failure and ensuing fire, is being replaced with more compact and reliable vacuum and SF 6 equipment. This will eventually flow through to a greatly reduced risk of failure and significantly reduced maintenance requirements. The replaced equipment is also smart grid ready, in that it would more readily interface with the modern protection, control and monitoring equipment that can provide the smarts to improve network performance Smart grid and smart metering Throughout the industry network businesses are investigating, and in some cases trialling, the application of so-called smart grid technology. The term smart grid is loosely used to cover a range of developments that when coordinated, can improve the performance of the distribution network and the customer experience. Smart grid technology may involve the following: the use of communications, in parallel with the distribution network, for various monitoring, control and protection functions; using communications to improve the performance of the network, by automatically switching to rearrange its configuration when there is a fault; using communications to inform the network operator of the status of the network and of any loss of supply to customer premises; and smart metering, equipped with communications, a customer interface and the ability to control certain loads within the customer s premises. Power Networks also recognises the potential for benefits to be obtained from smart metering. An increasing proportion of new customer connections are being equipped with meters capable of recording interval data, which is of great value in understanding customers consumption preferences and their impact on the network. However these installations are not considered to be smart meters. The term smart metering is usually applied to describe interval metering that is equipped with two way communications. This metering provides the customer interface for the smart grid developments discussed above. In addition to the remote reading of meter data, this metering can improve network management and facilitate demand management through combinations of communications, pricing and direct control measures. Power Networks will implement a trial of smart meters involving a representative sample size of customers in the current regulatory control period. This trial will enable the costs and benefits of advanced metering infrastructure technology in Page 35 of 110

37 the Northern Territory to be verified and enable a detailed assessment of the cost effectiveness of a larger smart meter rollout potentially carried out in future, after the regulatory control period. 4.3 Customer connections The majority of new and upgraded connections to the network are new dwellings therefore the number is directly related to the trend in building approvals. The number of connections to the network drives components of Power Networks capital and operating expenditure as follows: to provide the connection assets, a capital contribution may be required by the customer; augmentation may be required of assets forming the shared components of the network to supply the associated demand growth; and increased operating expenditure is required to maintain the additional assets, provide customer service and emergency response. The historical and forecast number of customer connections to the Power and Water network is illustrated in Figure 8. Figure 8 - Number of new and upgraded customer connections The forecast number of customer connections until 2018/19 is expected to revert to the long term trend, as economic activity returns to more normal levels. It should be noted that small scale solar photo-voltaic (PV) installations within residential and business premises do not ordinarily require a new or separate connection to the network. Rather, they utilise the existing load connection and generally do not require the connection to be upgraded. Peak demand forecasts are the principal driver for the augmentation of the network, as the network must be Page 36 of 110

38 able to supply those peaks with acceptable levels of system security, reliability and supply quality. 4.4 Demand forecasting Forecasts of the demand imposed on the network must be made for each location at which network capacity is required. This type of forecast is termed a spatial demand forecast and is usually carried out at more than one level in the network Demand forecasting procedure Power Networks develops demand forecasts for the network at the following levels: high voltage feeders (including major customer connections); zone substations (supplying the HV network); transmission (supplying groups of zone substations, major customers and major generators); and regional, covering the separate supply systems. The higher level network forecasts must make allowance for the diversity of demand, that is, the fact that individual loads at lower levels may occur at different times and so cannot be directly aggregated. As a consequence, while individual forecast demands may be summed to develop a total for the system, this is useful mainly as a comparison of the overall growth trend, rather than the magnitude of demand forecasts at higher levels. A diagram illustrating the sequence of the forecast process is shown in Figure 9. Page 37 of 110

39 Input data and modelling assumptions Accumulate and store historic demand data Network meters, large customers SCADA MDI, Survey Process improvement Adjust historic demand data Abnormal conditions or network configuration Abnormal customer loads Embedded generation Project historic data Weather conditions Day type Review planning outcomes Exogenous variables not captured by historical data Forecast reporting Regional demand forecast Modify projections Transmission substation forecast Changes to network configuration Known large customer load changes Known load developments Zone substation forecast High Voltage feeder forecast Forecast Reconciliation Figure 9 - Spatial demand forecasting process Power Networks identifies the underlying electricity demand growth for each zone substation and feeder based on the analysis and extrapolation of historic trends and known factors such as new loads and general population growth. 4.5 Darwin Katherine demand forecast Load factor trends The impact of growth on the network is not driven by energy consumption but rather by increasing demand. Either the network must be augmented to be capable of supplying that increasing peak demand or alternatively the demand may be managed within the capacity of the network by employing a range of approaches. It is therefore necessary to understand the relationship between energy growth and the corresponding demand growth. This ratio is termed the load factor and defined as; The load factor can be volatile and distorted by extreme peak days, so load factor is monitored over a period of time to better assess any developing trends. The historic load factor, based on temperature correct maximum demand in the Darwin Katherine system is shown in Figure 10 following. Page 38 of 110

40 Figure 10 - Load factor, Darwin Katherine System The long term load factor trend is decreasing indicating that the system is tending to be more peaky. This trend is not unexpected given recent significant tariff increase, which was expected to have a greater effect on energy consumption than on peak demand. The growing penetration of PV and other embedded generation is also likely to be having an effect on the load factor and will be of increasing interest if overall system demand slows significantly. Historically, between years the load factor can swing by 5 per cent between per cent, so while the 2013/14 year has a lower load factor than the immediate previous year it is not yet outside of what may be considered normal year to year variation. The long term trend may indicate a slowing in peak demand compared to energy consumption. Figure 11 displays both the full load duration curve for the Darwin Katherine system and also highlights the upper portion of the load duration curve for the Darwin Katherine system. It is this upper portion, near the time of peak load, which determines the need to augment the capacity of both the network and peaking generation resources. The relative sharpness of the annual trajectories provide an indication of the hours at risk, where loads may exceed the capacity of the network under contingency conditions. Page 39 of 110

41 Figure 11 - Load duration curves, Darwin Katherine System The load duration charts indicate the period of time during which peak conditions occur rather than considering only a single point in time (such as the peak demand). The load duration chart is based on actual values and indicates that the period of time during which the maximum 20 per cent load occurs is consistent with previous years. The most recent curve does suggest a potential improvement in load factor (in actual terms). This apparent difference from the previous Figure 10 may be due to the relatively lower temperatures at which the peaks occurred in the 2013/14 period. It also demonstrates the importance of long term trending of system data rather than relying on spot observations. System load profiles for each region are contained within Appendix A Weather correction of load history There is a dependency between the peak demand and the weather conditions on the day. In order to determine trends in the underlying growth, it is necessary to correct the recorded demand for the weather conditions. A number of weather recordings and derived factors were used to determine their relationship with the maximum demand: maximum daily temperature; average daily temperature (the average of the maximum and minimum recorded daily values); enthalpy (a combination of the temperature and humidity, intended to replicate the level of discomfort caused by hot, humid weather). Of these factors, the best correlation to demand was the maximum daily temperature. For the Darwin Katherine system, this was recorded at Darwin Airport. This correspondence is illustrated in Figure 12 for the wet season periods from 2006/07 to 2011/12. In this analysis, the demands on working weekdays (i.e. excluding public holidays and weekends) from November to March were used. The period from 25 December to 15 January was also excluded on the basis that normal operation for many commercial businesses and industries does not resume until well Page 40 of 110

42 into January each year. The R 2 value in Figure 12 indicates good correlation between demand and the maximum daily temperature Maximum daily demand y = x R² = Maximum daily temperature Figure 12 - Wet season day demand vs maximum daily temperature, Darwin Katherine System The temperature correspondence of Figure 12 was used in conjunction with the long-term distribution of maximum daily temperatures set out in Figure 13 13, to determine the Standard Weather Maximum Demand (SWMD) for the system. 13 Actual correlation was determined with data up to 2012 only. Page 41 of 110

43 Figure 13 - Wet season maximum daily temperature distribution, Darwin Katherine Each of the recorded maxima was corrected to this average temperature to represent the demand under standard weather conditions. As this demand would on average be exceeded in 50 per cent of wet seasons, it is also known as the P 50 demand. The distribution of the maxima is also used to determine the temperature which is exceeded in 10 per cent of wet seasons. This is also shown in Figure 13, and would give rise to a higher P 10 demand. The temperature correction parameters as determined in the forecasting process from 2012 have been applied for this forecast period. It is expected that these temperature relationships and correlations remain reasonable. It is also noted that the P50 temperatures have slightly increased in the Darwin Katherine region during the period from 2012 to 2014 from 35.9 Deg C to 36 Deg C. Similarly the P10 value has also increased from 36.7 Deg C to 36.8 Deg C during the same period. This change is minor and as such this data will be updated in future forecasts when the weather relationship is re-examined System demand forecast The regional forecast is determined by an assessment of the various spatial and economic forecasts as well as being supported by subjective indicators. As discussed previously in section there is a strong correlation between economic growth, when described by GSP and the Darwin Katherine region maximum demand. Using the NT Treasury forecast GSP figures and the long term GSP average, a GSP based SWMD forecast can be developed, as shown in the following Figure 14. Page 42 of 110

44 Figure 14 - GSP based SWMD forecast, Darwin Katherine System Further analysis of Figure 14 indicates two distinct growth rates in the forecast. These periods describe the transition in the economy that was previously discussed. In the short term the forecast shows the continuation of current growth drivers (green dashed trend line), followed by a steadying period in the long term (red dashed trend line). The historical trend (blue dashed trend line) is projected and shown for reference. The addition of PV systems into the network has the net-effect of reducing system load. Also due to PV system s inherent production nature, the systems will reduce energy consumption more rapidly than peak demand. This impact is likely to weaken the historic and future relationship between GSP and SWMD. The Darwin- Katherine region now has more than 10 MW of installed PV systems installed and is rapidly growing. Details on the PV uptake and MD Offset Factors applied for the regions are outlined in section of this document. These projections have been adopted in to explicitly allow for the future growth in PV installations in the demand forecast. The offset factor, of is the factor by which the installed PV capacity is expected to offset the system maximum demand. By applying this factor to the existing installed PV systems the influence of PV system on the historical system maximum demand figures can be removed. Once this influence was removed it was found that a strong correlation exists between these No PV historical maximum demand figures and GSP. In fact the linear relationship has a coefficient of determination of 0.89 indicating a stronger correlation than what exists between the GSP and standard weather maximum demand alone, without the PV adjustment. As such, in the same manner as the GSP forecast is shown in Figure 14, using the NT Page 43 of 110

45 Treasury forecast GSP figures, a GSP No PV demand forecast can be determined made as shown in red in Figure 15. This line represents the expected historical maximum demand and the GSP based forecast if PV systems had no impact on the system. Further to the GSP No PV forecast, by applying the forecast PV installation capacity from Figure 7, along with the MD offset factor (0.611) to the GSP No PV projection, a new forecast trend can be determined that considers the ongoing relationship between standard weather maximum demand to GSP, as well as the influence of PV systems. This trend is shown as the GSP PV Adjusted trend represented by the green line in Figure 15. As expected the green line displays the underlying GSP characteristics including the 2015 economic transition while also increasingly trending away and below the No PV scenario. Figure 15 - PV adjusted, GSP based SWMD forecast, Darwin - Katherine System Spatial demand forecasts are also developed from data recorded at each of the Zone Substations. This data is analysed, weather corrected, new loads are accounted for and then a least-squares linear regression line is applied to determine individual Zone Substation forecasts. Details on the forecast loads for each Zone Substation are contained within Appendix 3. Once the Zone Substation forecasts are summated, adjusted for diversity and expected new loads, this then provides a system forecast based on spatial data. The result of this is shown in Figure 16. Page 44 of 110

46 Figure 16 - Spatial SWMD Forecast, Darwin Katherine System Figure 16 also shows the historical growth trend (SWMD50), based on system level data projected forward for reference. Review of the previous forecasts as summarised in Table 9 using compound annual growth rates shows the forecasts to be in reasonable correspondence, given the different techniques by which they have been constructed, with their underlying assumptions and purpose. Table 9 - Forecast Reconciliation Darwin Katherine System Forecast GSP Forecast GSP Forecast, PV Adjusted Spatial Forecast Historical Trend (SWMD50) Comp. Annual Growth Rate 2.2 % 2.1 % 2.5 % 1.8 % Reference Figure 14, Red Trend Figure 15, Green Trend Figure 16, Purple Trend Figure 16, Green Trend Page 45 of 110

47 In assessing the regional forecast the following points are noted; The GSP to MD correlation is strong and as such the forecast based on Treasury figures is believed to be reliable. A forecast result above historical trend is supported based on economic indicators and comment. A forecast result above historical trend is supported based on spatial demand forecast. The spatial demand forecast, despite being adjusted is subjectively considered to be on the higher side, due to optimistic new load expectations. Similar transitions from high to lower growth rates are evident in both the GSP and spatial forecasts. PV systems are an increasing restraining influence on system demand Based on these considerations, the GSP Forecast (PV adjusted) has been adopted for the regional forecast as shown in Figure 17 following. High and low margins indicate one standard deviation based on historical SWMD variation. Figure 17 - System Demand Forecast, Darwin Katherine System For reference in Figure 17 the previous year s (2012/13) forecast of 2.7 per cent growth is shown. It should be noted that the previous forecast was accurate in regards to the 2013/14 maximum demand and is generally expected to align with the existing short term growth. However, following the economic transition from 2015/16 to more average growth, the previous forecast will tend to be high and less reliable. Page 46 of 110

48 4.6 Alice Springs demand forecast The Alice Springs power system is a small network that is interlinked and contains multiple generation points. This arrangement, together with recent changes to the network, transmission and generation systems, has created challenges in accurately determining the maximum load at a given point within the network. Overall system forecasts based on generation loads are reliable, however lower level forecasts are less reliable. Once the system migrates to its normalised feeder arrangement, additional work on the Alice Springs forecast for zone substations and feeders is required. Since Alice Springs is a much smaller network and regional centre than the Darwin- Katherine region, there is no obvious relationship between Territory wide economic performance and electricity demand, however similar to the northern region, the installation of PV systems across the network does affect system demand. As such demand forecasts are developed based on spatial data and adjusted for expected PV installations Load factor trends The trend in load factor for this system is illustrated in Figure 18. Figure 18 - Load factor, Alice Springs The Alice Springs system previously exhibited a markedly decreasing load factor coming down from a load factor 51 per cent in 2006/07. In recent years the load factor has been trending upwards and the long term average is recovering. Although further investigation is required, this high variation may be due to a high temperature variation in recent summer periods. The load duration curve for the Alice Springs system is shown in Figure 19. Note that the peak section has a different scale on the X axis to Figure 11, as this load is significantly peakier than for the Darwin-Katherine system. Page 47 of 110

49 Figure 19 - Load duration, Alice Springs This load duration curve mirrors the variation in load factors displayed in Figure 18, however the system load is significantly peakier than the Darwin- Katherine network. This is attributed to vastly differing weather patterns as well as high penetration of small solar PV generators in the area Weather correction of load history The best correlation to demand for the Alice Springs system was the maximum daily summer temperature recorded at Alice Springs Airport. This correlation is illustrated in Figure Maximum daily demand y = x R² = Summer maximum daily temperature Figure 20 - Summer day demand vs maximum daily temperature, Alice Springs Page 48 of 110

50 The temperature correspondence of Figure 20 was again used in conjunction with the long-term distribution of maximum daily temperatures similar to those set out in Figure 21 14, to determine the SWMD for the system. The maximum daily temperatures are significantly higher than those for the Darwin Katherine system. Figure 21 - Summer maximum daily temperature distribution, Alice Springs Each of the recorded maxima was corrected to this average P 50 temperature to represent the demand under standard weather conditions. For the 2013/14 forecast the average temperature for determining P 50 demand remained at 42.9 Deg C as determined in the 2011/12 forecast, rather than 43 Deg C as shown in the chart above. Similarly the P 10 value remained as 44.2 Deg C rather than 44.4 Deg C. These minor variations are immaterial in the forecast and the temperature correlation and averages will be reviewed and updated as required in the future. 14 Actual correlation was determined with data up to 2012 only. Page 49 of 110

51 4.6.3 System demand forecast The starting point for the development of the Alice Springs regional forecast is the temperature corrected trend based on system spatial data. The impact of solar generation is then considered to determine an adjusted regional forecast. The regional system load data indicates that in 2013 a summer record demand occurred earlier in the year than is usual and on a cooler day. This combination of high load and a cooler day resulted in a significant weather correction compared to recent years and more in line with demand from 2008/9 and 2009/2010. Figure 22 - Spatial SWMD Forecast, Alice Springs System The Feeder Scaled Unadjusted Forecast Trend is based on 11kV and 22kV feeder data and indicates steady growth of approximately 0.3 per cent on an annual compound growth rate. The Spatial Unadjusted Forecast based on Zone Substation data indicates a possible fall in overall demand into the future. These results highlight the challenges in forecasting load growth in a small interconnected system with variable weather and significant PV penetration. For the basis of this forecast the feeder forecast is considered most reliable as it is directly measured, whereas the substation loads are adjusted to accommodate for the 22kV transmission that occurs within Alice Springs. Page 50 of 110

52 Figure 23 - PV adjusted SWMD forecast, Alice Springs System Using the Feeder Scaled Unadjusted Forecast Trend as a basis, as well as the projected PV uptake for Alice Springs and the MD offset factor (0.595) as shown in Table 8, a forecast can be developed in consideration of the influence of PV. Figure 23 shows the historic standard weather maximum demand, MD50, as well as a trend representing the expected historical maximum demand if PV systems had no impact on the system, No PV. Further to this by applying the expected PV installation and MD offset factor a new forecast trend can be determined that considers the ongoing influence of PV systems. This trend is shown as MWP50 PV Adjusted and is represented by the green line in Figure 23 and has a compound annual growth rate over the period of 0.3 per cent. Since the spatial forecast and the PV adjusted forecast have the same characteristics over the period, the MWP50 PV adjusted forecast has been adopted as the regional forecast as show in Figure 24. High and low margins indicate one standard deviation based on historical standard weather maximum demand variation. The magnitude of the standard deviation is representative of the uncertainty associated with this forecast. Page 51 of 110

53 Figure 24 - System Demand Forecast, Alice Springs System 4.7 Tennant Creek demand forecast The Tennant Creek network is very small with a single point of generation and no transmission system. Due to these factors the forecast remains as a projected trend, without adjustment from economic factors or PV influences Load factor trends The trend in load factor for this system is illustrated in Figure 25 Figure 25 - Load factor, Tennant Creek System The load factor of Tennant Creek follows a similar trend to Alice Springs with no particular trend evident beyond year on year deviation. Page 52 of 110

54 4.7.2 Weather correction of load history Figure 26 - Load duration, Tennant Creek System With limited load history, the temperature dependence of the load in Tennant Creek is assumed to be the same as for Alice Springs with adjustments to the load made using the Tennant Creek Airport temperature records. Figure 27 - Summer maximum daily temperature distribution, Tennant Creek System For the 2013/14 forecast the average temperature for determining P 50 demand remained at 42.3 Deg C as determined in the 2011/12 forecast, rather than 42.4 Deg C as shown in the chart above. Similarly the P 10 value remained as 43.8 Deg C rather than 43.9 Deg C. These minor variations are immaterial in the forecast and the temperature correlation and averages will be reviewed and updated as required in the future. Page 53 of 110

55 4.7.3 System demand forecast The system demand forecast for Tennant Creek is shown in Figure 28. There is one known development planned in this area and the regional demand is expected to remain predominately static. Figure 28 - System Demand Forecast, Tennant Creek System 4.8 System Utilisation The following sections describe the utilisation of the major components of Power and Water s network Transmission line utilisation The table contained in Appendix A2 provides a listing of the Darwin Katherine system transmission circuits. For each circuit, the maximum flow under normal operating conditions has been considered against the design rating of the transmission line to determine line utilisation. The power flow under peak demand first contingency conditions is also examined, with contingency utilisation being determined by maximum conductor ratings. It should also be noted that both the normal and contingency utilisation levels in this table are indicative, based on the current rating of the items of equipment involved and 66kV bus voltage limitations. In practice, the rating of a transmission circuit may be limited to less than the thermal rating by other considerations, such as the maximum permissible voltage drop, steady state or transient stability. Page 54 of 110

56 The results of these studies indicate that under normal operating conditions the transmission line utilisation in the five year forecast period is acceptable as proposed works are completed, including the reconfiguration of the transmission system at Wishart Modular Substation and the construction of the Archer - Palmerston 66kV line. Based on the ten year forecast, the installation of a high capacity (120MVA) line between Hudson Creek and the new Wishart Zone Substation, will ensure all normal condition utilisation are maintained in the long term. Under contingency conditions, the study indicates that two 66kV transmission lines, Weddell-McMinns and Hudson Creek-Palmerston, may exceed their contingency ratings in 2015/16. The increase in loading is due to a number of new developments. Experience has shown that some of these developments may be delayed and the peak demand information provided by developers can be optimistic and above actual demand. On this basis, the timing of the requirement for a new transmission line from Archer to Palmerston has been adjusted to 2018/ Transmission terminal station and zone substation utilisation The zone substation utilisation for 2013/14 is shown in Figure 29. This is displayed for normal and first contingency conditions. For areas with the highest supply security class, class D, the second contingency is considered separately. Refer to Appendix A3 for details on each of the load areas. Figure /14 Transmission terminal station and zone substation utilisation In the case of first contingency conditions, most sites maintain area supply within the local zone substation. In some areas, the capacity of transformers is pooled between separate substations to maintain supply security to an area. As such some local zone substation contingency loads may exceed the 100 per cent installed capacity for a period prior to the completion of load transfer. These sites will be the subject of further studies to determine the most suitable ongoing arrangement pending area growth, operational limitations and system changes. Furthermore, a number of remote or single transformer substations do not have any local Page 55 of 110

57 transformer contingency capacity and have been indicated as No TF contingency. These sites also maintain the required security class via field switching to other sources and use a higher 10 per cent probability of exceedance in planning for future growth. The following points are made concerning the zone substation utilisation: the average utilisation, under normal conditions has increased from 34 per cent in 2012/13 to 38 per cent in 2013/14. This is due to increasing loads at existing sites. This utilisation is projected to stay steady at approximately 40 per cent in 2018/19 as load increases and new sites are commissioned; the average utilisation under first contingency conditions is 57 per cent; and it is evident from Figure 29 that there are a few locations where the transformer rating could be exceeded during contingency conditions. These sites are managed through load transfers and under these conditions utilisation is within cyclic ratings. It should be noted that a forecast load slightly in excess of the transformer rating is not necessarily an indication that immediate action to augment the transformer is required. Rather, it provides the trigger for more detailed investigation of the loading, potential load transfers and assessment of the risks involved. Power Networks also intends to carry out detailed analysis to determine whether a cyclic loading factor can safely be applied to transformers in the Territory s harsh climactic conditions, without unduly shortening their service lives. This has the potential to permit transformers to be subjected to loads in excess of their nameplate rating, for limited periods of time Distribution feeder utilisation Feeder utilisation is the ratio of the loading on a feeder to its normal capacity (no allowance has been made for any cyclic loading capacity utilising short term thermal capacity). In regard to what might be considered best practice levels of utilisation for the distribution portion of the network, the following observation was made in a recent Queensland distribution capital expenditure review, in relation to Ergon Energy 15 : 15 Darryl Somerville (chair), Electricity Network Capital Program Review Detailed report of the independent panel, December Page 56 of 110

58 Recommendation 20 Ergon Energy should bring its asset utilisation to a level consistent with good industry practice taking into account the regional nature of its network (i.e. 50 per cent to 55 per cent). The good industry practice utilisation level is applicable to HV feeders under normal conditions, for a network with a configuration and load density similar to that of Ergon Energy s network. Power and Water considers the Ergon distribution network, although larger and less sparse, to be of a similar nature. This utilisation level would ordinarily provide sufficient headroom capacity to restore supply following credible contingencies on the network 16. The charts in Figure 30 and Figure 31 compare the feeder utilisation for the most recent actual peak demand in 2013/14 with the forecast utilisation in 2018/19. Figure 30-11kV feeder utilisation The 11kV system includes both Darwin and Alice Springs 11kV feeders. The average 11kV feeder utilisation in 2014 is 47 per cent. This average increases to 58 per cent 16 A reasonably probable event such as the loss of a single transmission or distribution circuit, the loss of a single transformer or the loss of a single generating unit is known as a credible contingency event. Page 57 of 110

59 for 2019 and this includes additional new feeders from zone substations. Without the new feeders this figure would be exceeding 65 per cent, supporting the requirement for the additional feeders. In 2014 six feeders are indicated as having utilisation of greater than 100 per cent. Four of these feeders have been reviewed in detailed and despite having short periods of overload, the feeders are not over-utilised during normal operations. These feeders remain on watch and a number have works currently under way to reduce their utilisation and avoid the temporary overloads during abnormal system conditions. The remaining two overhead feeders in Alices Springs networks are overloading, up to 7 percent for very short peak periods. Feeder works are near completion to alleviate these overloads. Figure 31-22kV feeder utilisation Figure 31 shows only the 22kV feeders across the NT. These are generally rural feeders with very little, if any, contingency capability. The utilisation of feeders is based on the load divided by the capacity of the feeder. Power Networks has a number of standard conductors but with rural systems the reason for using the larger size conductors is not to provide capacity but to reduce voltage drop due to the long distances. For this reason it is expected to have low utilisation. In 2014 the average 22kV utilisation was 24 per cent and this increases to 29 per cent in This is a significant increase and is due to some mine sites as well as commercial and residential development in the Darwin rural region. Overall average feeder utilisation (11kV & 22kV) since 2011/12 has remained steady at 42 per cent. At the end of this forecast period it is expected that average feeder utilisation will be around 52 per cent. This is comparable with peer organisations and in line with the best practice average. Page 58 of 110

60 It should be noted that feeders with utilisation approaching 100 per cent (or greater than 100 per cent in 2019) will be placed on a watch list and will require remedial action, which generally includes one or more of the following actions: ongoing monitoring of load growth; calculation of cyclic capacity to determine if higher ratings can be achieved for short term peaks; the construction of an additional feeder; augmentation of the capacity of the feeder; rearrangement of the network; the construction of an additional zone substation; or the transfer of loads to adjacent feeders Distribution transformer utilisation Relatively few of Power Networks distribution transformers are equipped with maximum demand indicators and thus monitoring their utilisation is problematic. In common with many distributors, Power Networks upgrades the capacity of distribution transformers where: new and upgraded connections would exceed the rating of a transformer; fuse or protection operation indicates a potential loading issue; or a transformer fails due to overloading. Installing maximum demand indicators on all of the distribution transformers is not cost effective. Smart Grid developments, using sensors to detect transformer loading, may eventually yield an economic retrofit solution, to assist in managing transformer utilisation. Based on some initial research, Power Networks believes it may be possible to develop a screening approach to determine the transformer utilisation from customer revenue metering records, which can be associated with the individual distribution transformers and HV feeders. Clearly, the apportionment of feeder loading to individual distribution transformers on the basis of energy consumption involves simplifying assumptions on customer demands and diversity, unless each customer is equipped with an interval meter. Nevertheless, Power Networks proposes to develop this approach and employ it as a screening test that would indicate where closer inspection or the monitoring of a particular distribution transformer might be warranted. Page 59 of 110

61 5 ASSET MANAGEMENT Power Networks is maturing its asset management capability. Previous areas of poor performance have demonstrated improvements that have been sustained. Plans have been developed that will further consolidate the performance by targeting those areas where the greatest benefits lies as determined by asset condition indicators. The preventative maintenance culture has grown steadily over recent years providing quality information for a large number of asset classes. This information is analysed to reshape the maintenance and replacement programs for the Power Network. The current asset management regime makes use of contemporary philosophies and work practices such as the use of mobile devices to validate assets and perform preventative maintenance that captures condition information. These practices build information providing the foundation for prudent and efficient decision making. Page 60 of 110

62 5.1 Background Sound maintenance practice is fundamental to asset intensive businesses as it provides the opportunity to understand the asset condition. The preventative maintenance performance of Power Networks has shown improvement since being introduced in In completion of preventative maintenance tasks was 90 per cent. The tasks conducted during preventative maintenance are designed to prevent failures thereby improving the reliability of the plant. This is in line with the objective need principle where assets are maintained based on their requirements and maintainers are skilled in the delivery of these works. The introduction of the Maximo and the ESRI Geospatial Information System (GIS) in September 2012 focused the attention of the organisation on the quality of asset information. The processes used to capture this information and drive the business were mapped to determine the required system functionality. The 2013 KPMG report Asset Management Capability (AMC) Systems Analysis and Roadmap identifies 18 key asset management processes where further improvement was required to enhance Power and Water s asset management capability. It has been identified that customisations of the Maximo software increase the complexity and risk of software upgrades that are essential in order to maintain vender support and exploit software enhancements. The Asset Management Capability project was reformed to deliver these works for all of Power and Water Corporation s operational business units. Power Networks has engaged with the reformed Asset Management Capability project to address the concerns raised in the report. The approach is to document the business processes and identify where they are supported by Maximo without customisations. This simple exercise results in improved task definition, responsibility for employees operating in the process and visibility for those who are required to provide support and improvements. Where it is determined that the out of the box software does not support the business process, other solutions will be developed. This project is currently underway and is expected to continue into the financial year. Since the Maximo/Esri introduction Power Networks has levered much of the standard Maximo functionality to improve its management of assets. Particularly, it has utilised a feature that allows for the definition of assets part/failure/cause to develop standard failure hierarchies for assets. These are being used by maintainers who provide information to the business that is critical for developing responses for asset failures and understanding their impact on the business. This leads to the ability to report operational risk thereby providing decision makers a link between failures, risk and ultimately cost to optimise maintenance. Much effort is being employed by Power Networks to develop the part, failure and cause hierarchy as this information provides a cornerstone of the risk posed by the assets. Page 61 of 110

63 5.2 Asset management policy Power Networks has documented the policy by which it will maintain its network assets, to achieve the following objectives: established standards of safety, reliability, quality of supply and operational efficiency; other obligations imposed by statute, the regulator and relevant industry codes; an economic balance between the cost of maintenance, compared to replacement or refurbishment, so as to achieve minimum asset life cycle cost; and other defined business objectives, including neat and tidy buildings, grounds and network asset integrity consistent with the Occupational Health and Safety principles. The asset management policy effectively covers all network assets, including: network electrical assets, associated buildings, grounds, easements, access roads, tracks and the like; and secondary systems covering DC power supplies, communication, SCADA and protection equipment. 5.3 Asset condition In common with other network service providers, Power Networks is faced with maintaining and renewing a suite of network assets that are aged (by industry standards) and progressively growing older. Additionally, the climatic and environmental conditions of the Northern Territory lead to the accelerated deterioration of assets. It is therefore reasonable to propose that in the Northern Territory context, asset age is a reasonable surrogate for asset condition. The external environmental factors and the age of the assets represent increased hazard for a number of risk domains for the Power Network business. This risk can only be managed by maintenance composed on the objective need principle and replacement activity. The review of Power Networks asset management practices has resulted in: an increase in Power Networks operating and maintenance expenditure; and increased capital expenditure to enable the accelerated replacement of unserviceable equipment. The age profiles of some representative major classes of network equipment are presented in Figure 32. The charts cover assets in the three regulated electrical systems, Darwin-Katherine, Tennant Creek and Alice Springs. It should be noted that replacement activity at Woolner, Manton and Katherine zone substations have reduced the number of aged assets and increase the number of asset in the 0 to 10 Page 62 of 110

64 year range. This trend is expected to continue as capital expenditure results in more replacement activities. Figure 32 - Age profile of transmission terminal station and zone substation equipment The equipment age profile highlights: a significant proportion of the outdoor switchgear and indoor high voltage switchgear is over 40 years of age and near the end of its useful life; and a significant proportion of the power transformers are in the same age category. The replacement of aged switchgear and transformers is being addressed through the capital expenditure plan. Figure 33 - Age profile of distribution substations Page 63 of 110

65 The age profile of distribution transformers is considered satisfactory, with less than 4 per cent aged greater than 40 years. 5.4 Maintenance categories Power Networks maintenance is broadly divided into four groups: Preventative Maintenance, Planned Corrective Maintenance, Unplanned Corrective Maintenance and Specific Maintenance. These four groups form the foundation of the maintenance regime and feed valuable condition information to the asset team for analysis. Despite only being established for a relatively short time, they continue to produce valuable information and have prevented a number of catastrophic failures. The objective of maintenance is to: maintain the functional performance of the assets; identify potential problems before the condition of assets is compromised; minimise damage to assets during faults; avoid or limit the duration of customer supply interruptions; enable a planned and structured approach to repair or replacement of assets; reduce risk to personnel and public; and mitigate public liability risk. Some of the details of the maintenance categories are presented below Preventative Maintenance The three main objectives of Preventative Maintenance are to confirm the function of the asset, diagnose the condition of the asset and keep the asset in good working order until the next Preventative Maintenance cycle. Although the maintenance is conducted periodically, it has a strong condition basis through the application of three types of Preventative Maintenance: functional, diagnostic, and intrusive, which have a cascading relationship. Diagnostic maintenance includes the tasks undertaken during functional maintenance plus some additional tasks designed to measure the condition of the asset. Intrusive maintenance includes all the tasks of the diagnostic plus some that can only be completed during a comprehensive disassembly of the asset. Each asset class, model and/or make may have up to three different maintenance types scheduled to be completed at differing intervals. All diagnostic and intrusive maintenance types commence with the measurement of key condition indicators to provide the as found condition. If work is undertaken during Preventative Maintenance to restore an aspect of the condition to the required specification, measurements are made after completion to give the as left condition. Activities requiring a large degree of disassembly of the asset are kept to a minimum to reduce the time taken to complete maintenance and avoid maintenance induced failures. Page 64 of 110

66 A small number of asset classes have maintenance that must be completed as a result of the number of operations of the asset. These are termed meter based maintenance and the tasks undertaken relate to restoration to specification of the elements or components that would experience wear as a result of it operating. Condition information is also captured during these activities Planned and Unplanned Corrective Maintenance Over time, Power Networks is expecting a decline in the amount of Corrective Maintenance. A focus on Preventative Maintenance is widely acknowledged to lead to a decline in the number and severity of asset defects that require correction. However, defects are still expected to occur and the Maximo Asset Management System captures corrective maintenance and facilitates its prioritisation. Corrective work that requires immediate rectification receives a Priority 1 rating and is considered unplanned. Other Corrective Maintenance tasks receive target completions periods of one month, nine months or next periodic maintenance interval providing opportunities to plan the work. When corrective maintenance is completed, the part, failure and cause are captured and held against the asset involved in the failure. The introduction of mobile devices is now allowing this information to occur at the point of the failure in the field, leading to improved reporting accuracy. This critical information can then be analysed to determine the effectiveness of the preventative plan and is used to optimise the plan through changes in task or intervals. The information also provides guidance on the consumption and timing of spare parts that can be analysed to set the minimums and maximums of inventory as the maturity of asset management grows Specific Maintenance Specific Maintenance addresses specific issues that exist in an asset or asset class. The need for Specific Maintenance may be identified through the analysis of asset condition data or failures in particular classes of assets. 5.5 Asset management processes Power Networks has developed detailed asset maintenance processes that ensure best practice asset management and clear identification of the responsibilities and appropriate handover points between the teams involved. A high level flow diagram for the asset maintenance cycle is show in Figure 34. Page 65 of 110

67 To Capex Strategy & Planning Branch Maintenance Review Service Delivery Branch Strategy & Planning Branch Maintenance Planning Budget Finalisation Plan Works Schedule Work Perform Work Complete Work Close Work Maintenance Reporting Figure 34 - Asset Maintenance Cycle Importantly, Figure 34 highlights the feedback loop, whereby the maintenance reporting function provides critical data on the asset condition of Power Networks assets. As this data is processed consideration is also given to the performance of like assets in national and international jurisdictions. Other factors such as safety, expected loading and strategic network objectives are also considered in the review of maintenance planning practices and, where appropriate, investment in assets and their renewal or refurbishment. Power Networks Asset Management Strategy identifies the core preventative maintenance and condition monitoring tasks for each asset class 17. Analysis of the risks of asset failures are undertaken using Failure Mode, Effects and Criticality Analysis (FMECA) which has been performed with input from asset maintainers and planners, safety officers, test and protection personnel, engineering and external consultants. This identifies the risks that are then mitigated through a Reliability Centred Maintenance (RCM) approach. The equivalent high level flow diagram for the asset capital expenditure process is shown in Figure 35. Although the responsibility for this activity lies within the Strategy and Planning Branch, the activities of different work teams are identified in the detail of the process flow. 17 Power Networks Asset Strategies Procedure D2013/ Page 66 of 110

68 Strategy & Planning Branch Maintenance Review Capital Investment Planning Budget Finalisation Project Planning Project Design Project Construction Project Completion Project Close Capital Investment Reporting Figure 35 - Capital Expenditure Process The capital expenditure process in Figure 20 has been used in developing the capital expenditure program in this Plan. The figure shows the stages in the development of a project, from planning inception through to completion and the reporting of assets. Feedback from the maintenance review is used to develop the refurbishment and replacement elements of the program. 5.6 Asset management systems Improvement in the asset management practices of Power Networks is well underway through the implementation of new systems. The introduction of Maximo and ESRI (GIS mapping software) has provided immediate enhancements to Asset Management capability and capacity. The Integrated Distribution Management System (IDMS) or Operation Management System (OMS) will further enhance outage recording capability and provide valuable insight into the operating regime. A limited trial of mobile field devices used for Preventative Maintenance tasks, commenced in March This trial was well received by field staff who compared the field asset name plate details with those held in Maximo (asset validation) and captured asset defects. The devices also provide field staff access to documents containing maintenance and safety information and other features typically available such as street maps and a restricted web browser. Field devices are now used extensively for preventative maintenance work which has resulted in significant saving for Power Networks. A project to integrate the field devices with Maximo is underway which will automate the upload of the asset condition information described below with Maximo. The integration also has the functionality of indexing the work order status and raising defects found during preventative maintenance. Asset condition information is captured by Maximo in two ways. Firstly, measurements made during preventative maintenance are entered into the system as metered values that are held against the asset. Secondly, information obtained during corrective maintenance is captured as maintainers record the component, failure mode and cause of the asset failure through a structured hierarchy (failure class) that is unique to each asset class. As highlighted above, the failure classes have been further developed and expanded and are now able to be accessed by maintainers in the field with mobile devices. This greatly improves the quality of this information. Both condition and failure data will be utilised in the analysis of maintenance and replacement regimens for all assets in the asset base, as a routine component of the maintenance cycle. Page 67 of 110

69 One example of how this information will be utilised is in the areas of restricted assets. A manual process is currently used to report asset restrictions for assets that present an unacceptable or unknown level of risk. The restriction relates to the access (including assets in the vicinity) or operation of these assets and is critical from a safety perspective. Assets are typically restricted due to an out of specification maintenance result, overdue maintenance by more than six months and/or a known failure mode that may place personnel at risk. The latter condition can be detected in-house, from another jurisdiction or from the original equipment manufacturer. The restriction requires increased Personnel Protective Equipment (PPE) until the asset is condition assessed. This occurs daily while personnel are in proximity to the assets after which the requirement reverts to normal PPE. The Maximo asset system was designed to capture outage information when keyed by System Control. However, its implementation has resulted in lower resolution and accuracy of performance data particularly with regard to partial restoration of outages. A project to deliver either an Integrated Distribution Management System (IDMS) or an operation management system (OMS) is currently being considered. The system enhancements mentioned above are essential to the sustainable development of the Power Networks business. Technological advances, particularly in mobile computing, provide enormous opportunities to improve data capture and dissemination that ultimately results in enhanced capability and capacity at reduced cost. 5.7 End of life management As discussed above, some network assets are ageing and are overdue for replacement. To ensure these assets continue to perform in a safe and reliable manner, maintenance and monitoring of these assets must be a priority. To enable these functions, sufficient spares and replacements must be held to restore assets to service after failures. Power and Water has established a corporately centralised warehouse/store function and an electrical parts supply panel contract. The panel contract introduces greater competition into parts supply and has significantly lowered prices on some items. Power Networks has also invested in the establishment of warehouses and store rooms to manage spare parts, consumables and replacement assets. This ensures that parts and replacement assets are correctly stored and locatable whenever they are required. A dedicated essential spares coordinator is embedded within the asset management team and works closely with standards and asset engineers to identify the required spares and procure them. These parts are then managed by the corporate stores function. As assets age, it is critical that every effort is made to procure spare parts and replacements, and carefully maintain these stocks until the assets are retired in line with the capital investment program. Page 68 of 110

70 5.8 Strategic asset plans Detailed strategic asset plans have been completed for all major asset classes and applied since Enhanced system capability from Maximo that captures asset failure and condition data will be utilised to further optimise the maintenance plan. The new asset system will facilitate the refinement of detailed asset management plans for each asset class. Each year consideration of conditional and functional failures and asset as found condition is given which often results in changes to the frequencies and/or tasks thereby optimising the maintenance plan. Beyond this window the process will be further enhanced through more targeted asset failure and condition data, coupled with consideration to risk that will provide a more detailed statistical analysis. The strategic asset plans focus on improving the safety, reliability and operability of assets. Some examples of this process of continuous improvement are: targeted feeder upgrades have been defined by analysing outage information to identify poorly performing feeders using the System Average Interruption Duration Index (SAIDI) and other Standards of Service measures. Outage information currently contains the asset, cause, protection that operated and the percentage of feeder affected. Each of these factors is considered, along with the level of the completion and effectiveness of past upgrades, in determining what further measures should be employed to improve the performance of individual feeders. The asset condition knowledge held by maintainers is also exploited as any suggested improvements are reviewed and finalised with the relevant work teams; McMinns Zone Substation, City Zone Substation, Berrimah Zone Substation and Casuarina Zone Substation 66kV Outdoor Switchyard are all approaching end of life. Assets at these sites pose a considerable risk to Power Networks that is being carefully managed. Regular reviews of Defective Asset Reports at sites approaching end of life are conducted to ensure maintenance and repair activities adequately reduce the risk of failure. The implementation of the Early Contractor Involvement contract has so far been effective in delivering the substantial asset replacement program identified above; and other high risk assets that have been targeted for replacement include Oilfilled Ring Main Units (ORMUs) and zone substation oil filled circuit breakers, which have been known to fail catastrophically. Similarly, air insulated BBC 11kV distribution switchgear has a high rate of failure and a restricted operating regime. These asset classes are being monitored with partial discharge and thermal scans until the replacements can be completed. 5.9 Asset replacement As noted earlier, the Repairs and Maintenance programs have transitioned away from a predominately corrective approach to one of preventative maintenance based on asset condition. There is a point in the condition of an asset when the Page 69 of 110

71 best outcomes are received by managing the end of life until replacement and these strategies have been described above. By the end of the forecast period covered by this Plan, some network assets will be reaching ages where decreased performance can be expected. This is highlighted by the age profiles of assets in section 5.3. The major network assets that require careful planning for upgrade or replacement due to their criticality and high replacement costs are zone substation power transformers and circuit breakers: Zone substation power transformers These are regularly assessed with oil testing and more recently electrical testing to determine their electrical age and internal condition. Power Networks is collaborating with one of its suppliers to develop an analysis tool that assists in the review of power transformer condition. This will enhance the assessment capability and optimise the replacement activity. Current replacements are occurring, primarily as part of major zone substation upgrade or rebuild projects. Circuit breakers The condition of 66kV circuit breakers has been assessed and some will require replacement. All remote/rural 66kV circuit breakers will be replaced with the dead-tank type and urban 66kV circuit breakers will be replaced with the live-tank type. Dead tank breakers have a larger footprint but incorporate current transformers within the bushings of the breaker, reducing the number of items of equipment and associated maintenance costs. In urban areas it will be more cost effective and efficient to install live tank breakers (like for like). In both cases Power Networks has period contracts in place for the supply of these circuit breakers. The Darwin-Katherine Transmission Line (DKTL) 132kV pneumatically operated AEG breakers have proven unreliable and maintenance intensive. A program has been established to replace these breakers over a three year period with the breakers located at Katherine already replaced. The Pine Creek breakers will be replaced in 2014/15 and Manton in 2015/16. Page 70 of 110

72 6 CUSTOMER STANDARDS OF SERVICE 6.1 Introduction This section quantifies the performance of Power and Water s regulated network using nationally recognised indicators to the target standards set by the Commission. The efforts made to address the performance of poorly performing feeders are presented along with other significant works. The performance with regard to power quality is detailed, as is a brief summary of the activities associated with maturing asset management. 6.2 Network reliability Power and Water s service performance is highly dependent on weather conditions throughout the year. The Bureau of Meteorology states that the wet season ended near the long-term average 18. Tropical Cyclone Alessia was the only tropical cyclone to make landfall and brought an intense wet period in November Network performance in was characterised by a delayed start to the wet season and periods of increased rainfall with the wettest November on record. On 12 March 2014, the Darwin-Katherine system experienced a system black event. The majority of customers in the region lost electricity supply at 1:19am and were restored later that afternoon. The trigger for this event was a circuit breaker malfunction at Hudson Creek Terminal Station during routine switching operations. The vulnerability of the system to events such as the March 2014 system black are being addressed through the Hudson Creek 132kV circuit breaker replacement program, protection upgrades and bay extension. The network remains vulnerable to extreme weather events such as severe storms and tropical cyclones that damage overhead lines and can blow debris into substations causing widespread outages. The 132kV transmission lines between Hudson Creek and Channel Island Power Station is currently vulnerable to a low end category 3 cyclone at the Elizabeth River crossing area. A project has commenced to upgrade this section of line to a category 4 level and is due for completion prior to the wet season Page 71 of 110

73 The relationship between service performance and rainfall is demonstrated in Figure 36. In this figure the Darwin monthly adjusted SAIDI for vegetation on the overhead network from July 2004 is compared to the Darwin monthly rainfall over the same period 20. A strong relationship in the timing of the rainfall periods and SAIDI is obvious although the severity of weather does not necessarily align with the magnitudes of SAIDI. Darwin Monthly Vegetation SAIDI and Darwin Monthly Rainfall Darwin Adjusted SAIDI for the cause code Trees blown & Growing into Main s Monthly Rainfall (mm) System SAIDI (mins) Monthly Rainfall (mm) Jul 2004 Jan 2005 Jul 2005 Jan 2006 Jul 2006 Jan 2007 Jul 2007 Jan 2008 Jul 2008 Jan 2009 Jul 2009 Jan 2010 Jul 2010 Jan 2011 Jul 2011 Jan 2012 Jul 2012 Jan 2013 Jul Figure 36 - Darwin Monthly Vegetation SAIDI and Darwin Monthly Rainfall 20 Page 72 of 110

74 6.3 Transmission network performance against targets Power Networks met the ACOD and ATOD target standards in the Darwin-Katherine power system during the reporting year. The FCO and FTO target standards were exceeded as shown in Table 10. Table 10 - Darwin-Katherine transmission performance indicators Transmission Performance Indicators Average Circuit Outage Duration (ACOD) (mins) Frequency of Circuit Outage (FCO) Average Transformer Outage Duration (ATOD) (mins) Frequency of Transformer Outages (FTO) Target Standard Darwin- Katherine Adjusted Results Target Standard Met Yes No Yes No Power Networks met all target standards in the Alice Springs power system during the reporting year as shown in Table 11. Table 11 - Alice Springs transmission performance indicators Transmission Performance Indicators Average Circuit Outage Duration (ACOD) (mins) Frequency of Circuit Outage (FCO) Average Transformer Outage Duration (ATOD) (mins) Frequency of Transformer Outages (FTO) Target Standard Alice Springs Adjusted Results Target Standard Met Yes Yes Yes Yes The transmission FCO cause breakdown for the Darwin-Katherine system is shown in Figure 37. The most significant cause of outages is No Cause found Weather. While no cause is found for these interruptions, they have likely resulted from wind and lightning related faults. In Power Networks will implement a program to test the earthing on transmission towers as well as conducting a lightning performance study on the two Hudson Creek Channel Island Power station 132kV transmission lines. It is anticipated that subsequent corrective actions will result in fewer lightning related interruptions on these lines. Page 73 of 110

75 Transmission FCO Cause Breakdown Other, 17% Animals, 6% Equipment - Failure or Defect, 13% Safety PWC, 4% Overload, 6% Human Error, 4% Lightning, 8% No Cause Found - Weather, 23% No Cause Found - Not Weather, 19% Figure Transmission FCO cause breakdown The Transmission FTO cause breakdown for the Darwin-Katherine system is shown in Figure 38 and was due to Animals Transmission FTO Cause Breakdown Animals 100% Figure Transmission FTO cause breakdown 6.4 Distribution network performance against targets Power Networks met the SAIDI target standards in one out of the four feeder categories (Table 12). The target standard was exceeded in the CBD, Urban and Rural Short feeder categories during When outages related to the Darwin- Katherine system black event are removed, all feeder categories meet the required performance. It should be noted there is low confidence in the data presented for the Rural Long feeder category due to system technical issues. Page 74 of 110

76 Table 12 - Distribution SAIDI results segmented by feeder category (adjusted) Feeder Categories Adjusted SAIDI Target Standard (minutes) Adjusted SAIDI Results (minutes) Adjusted SAIDI Results (minutes) excluding System Black Target Standard Met CBD No Urban No Rural Short No Rural Long Yes Power Networks met the SAIFI target standards in three out of the four feeder categories (Table 13). The target standard was exceeded in the CBD feeder category. When the effects of the Darwin-Katherine system black event are removed, all categories meet the required performance. Table 13 - Distribution SAIFI results segmented by feeder category (adjusted) Feeder Categories Adjusted SAIFI Target Standard Adjusted SAIFI Results Adjusted SAIFI Results (excluding system black) Target Standard Met CBD No Urban Yes Rural Short Yes Rural Long Yes As stated above, all targets are met when the system black event is excluded. The Darwin-Katherine system black was a major event day but is not excluded from the adjusted results because it was not from a natural cause. The event has been extensively investigated and the root cause determined to be circuit breakers of poor condition at Hudson Creek Substation. Half of these circuit breakers have been replaced and the remaining breakers are to be replaced next dry season. It is important to note that the cause codes below include the system black event data although the commentary will look beyond this event to address underlying reliability issues. The works that are being planned and undertaken that are discussed below have been determined through the analysis of the causes of 2013 calendar year reliability. This facilitates a more dynamic response between reliability issues in the annual works planning activity. Page 75 of 110

77 Central Business District (CBD) There are a number of significant upgrade works that are scheduled for completion late in that will contribute to the longer term reliability performance of the CBD. The works include a new transformer at the Frances Bay zone substation and the construction of the Darwin zone substation which replaces the aged City zone substation. Planned works in the distributed network include switching station upgrades and Oil Ring Main Units (ORMU) replacements. The main drivers for ORMU replacement are safety and reduced maintenance cost, but there will also be a positive impact on both SAIDI and SAIFI. SAIDI Overload 0% SAIFI Overload 0% Equipment - Failure or Defect 100% Equipment - Failure or Defect 100% Figure CBD SAIDI and SAIFI causes Urban Feeder Category The most significant cause of outages in the urban feeder category is Equipment Failure or Defect (Figure 40). Equipment issues were due to cable termination failures and fuses. Works planned for include upgrading affected equipment and installing equipment to reduce the duration of these types of outages. The vegetation program for included increased tree trimming which has led to a reduction of outages in this category from that of the previous year. Feeder upgrade works planned for targets overhead line hardware and failures due to high voltage (HV) bridges by installing permanent connections. Other planned works include the installation of equipment which will allow for quick isolation and restoration of supply to customers. This will limit the number of customers affected by faults thereby improving SAIDI and SAIFI performance. Page 76 of 110

78 No Cause Found - Not Weather Lightning 2% 2% Human Error 1% SAIDI No Cause Found - Weather 0% Trees Blown into Mains 2% Other 1% Equipment - Failure or Defect 92% SAIFI Safety PWC 2% No Cause Found - Weather 7% No Cause Found - Not Weather 9% Trees Blown into Mains 7% Lightning 3% Other 4% Equipment - Failure or Defect 68% Figure Urban SAIDI and SAIFI causes Rural Short Feeder Category The most significant cause of outages for the rural short feeder category is Equipment failure or Defect (Figure 41). There has been a significant reduction in outages due to Trees Blown into Mains compared to last financial year due to an increase in vegetation management activities and the feeder upgrade program. Other significant causes of outages were No Cause Found Not Weather. These interruptions are caused by faults that are transient in nature. These faults remain on the power line for a brief period of time before being cleared. In Power Networks installed a large number of automatic sectionalising switches to minimise the area affected by a transient fault and to restore power as soon as practical. Animals was also a significant cause of outages and the installation of animal protection in resulted in less outages compared to There are numerous feeder upgrade works planned for on rural short feeders. Increased automation of the network promotes faster isolation of faults and improves restoration time. This reduces SAIDI and the cost associated with restoration. The traditional approach of upgrading overhead line hardware will continue as these have proven to have a positive impact on feeder reliability. Other works include the provision of overhead line fault indicators for aiding in fault location and reduced restoration time, new GCRs to limit the customers affected by faults and the installation of new fuse savers to reduce the duration of interruptions for HV fuse operation for transient faults. Page 77 of 110

79 SAIDI No Cause Found - Weather No Cause 3% Found - Not Weather 6% Lightning 1% Forced Outage 1% Overload 3% Trees Blown into Mains 3% Other 1% Animals 5% Equipment - Failure or Defect 77% SAIFI Overload 2% No Cause Found - Weather 20% No Cause Found - Not Weather 22% Safety PWC 1% Trees Blown into Mains 5% Other 1% Animals 6% Equipment - Failure or Defect Forced 41% Outage 2% Figure Rural Short SAIDI and SAIFI causes Rural Long Feeder Category There are currently just two feeders in the rural long category and they have been targeted with works to improve reliability since The works included the installation of a number of switches and reclosers and increased vegetation management. Despite the data issues stated above, it is expected that the performance of these feeders has improved as a result of these works and no reliability works are scheduled for SAIDI No Cause Found - Weather 59% Overload 1% Equipment - Failure or Defect 24% Human Error 1% Lightning 1% No Cause Found - Not Weather 14% SAIFI No Cause Found - Weather 35% No Cause Found - Not Weather 36% Overload 1% Equipment - Failure or Defect 27% Human Error 0% Lightning 1% Figure Rural Long SAIDI and SAIFI causes 6.5 Network performance indicators The Code requires reporting of the unadjusted transmission performance indicators along with transmission SAIDI and SAIFI. There are no target standards associated with these indicators. Results for the reporting year are shown below. Table 14 - Unadjusted power system transmission performance Transmission Performance Indicators Unadjusted Average Circuit Outage Duration (ACOD) (mins) Unadjusted Frequency of Circuit Outage (FCO) Darwin-Katherine Alice Springs Unadjusted Average 55 0 Page 78 of 110

80 Transformer Outage Duration (ATOD) (mins) Unadjusted Frequency of Transformer Outages (FTO) 1 0 Table 15 - Power system transmission SAIDI and SAIFI Transmission Performance Indicators Darwin-Katherine Alice Springs Unadjusted SAIDI (mins) Adjusted SAIDI (mins) Unadjusted SAIFI Adjusted SAIFI The Code requires reporting of the distribution unadjusted and adjusted SAIDI and SAIFI by feeder category and region. There are no target standards associated with these indicators. Results for the reporting year are shown below. Table Distribution unadjusted SAIDI by feeder category and region Region CBD Urban Rural Short Rural Long Darwin NA Katherine NA Tennant Creek NA * 196 Alice Springs NA NA *This high value is due to the low number of customers in the Tennant Creek Rural Short area. Table Distribution unadjusted SAIFI by feeder category and region Region CBD Urban Rural Short Rural Long Darwin NA Katherine NA Tennant Creek NA Alice Springs NA NA Table Distribution adjusted SAIDI by feeder category and region Region CBD Urban Rural Short Rural Long Darwin NA Katherine NA Tennant Creek NA Alice Springs NA NA Page 79 of 110

81 Table Distribution adjusted SAIFI by feeder category and region Region CBD Urban Rural Short Rural Long Darwin NA Katherine NA Tennant Creek NA Alice Springs NA NA The Code requires reporting of the unadjusted SAIDI and SAIFI by feeder category and SAIDI and SAIFI by region. There are no target standards associated with these indicators. Results for the current reporting year are shown below. Table Unadjusted SAIDI and SAIFI by feeder category Feeder Categories Unadjusted SAIDI Unadjusted SAIFI CBD Urban Rural Short Rural Long Table SAIDI by region Region Adjusted SAIDI Unadjusted SAIDI Darwin Katherine Alice Springs Tennant Creek Table SAIFI by region Region Adjusted SAIFI Unadjusted SAIFI Darwin Katherine Alice Springs Tennant Creek Yearly SAIDI and SAIFI trends by feeder category This section contrasts the current and historical reliability performance of each feeder category. The accumulated adjusted values for both SAIDI and SAIFI are presented for each feeder category. Each graph shows the seasonalised target, annual result, a five year average and annual result, with the Darwin-Katherine system black event excluded. Page 80 of 110

82 The works to address reliability are outlined in the Distribution network performance against targets section, along with data confidence levels for Rural Long feeders. CBD Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Seasonalised SAIDI Target (excluding System Black) Average Figure 43 - Accumulated CBD adjusted SAIDI trends Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Seasonalised SAIFI Target (excluding System Black) Average Figure 44 - Accumulated CBD adjusted SAIFI trends Page 81 of 110

83 Urban Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Seasonalised SAIDI Target (excluding System Black) Average Figure 45 - Accumulated Urban adjusted SAIDI trends Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Seasonalised SAIFI Target (excluding System Black) Average Figure 46 - Accumulated Urban adjusted SAIFI trends Page 82 of 110

84 Rural Short Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Seasonalised SAIDI Target (excluding System Black) Average Figure 47 - Accumulated Rural Short adjusted SAIFI trends Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Seasonalised SAIFI Target (excluding System Black) Average Figure 48 - Accumulated Rural Short adjusted SAIDI trends Page 83 of 110

85 Rural Long Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Seasonalised SAIDI Target" (excluding System Black) Average Figure 49 - Accumulated Rural Long adjusted SAIDI trends Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Seasonalised SAIFI Target (excluding System Black) Average Figure 50 - Accumulated Rural Long adjusted SAIFI trends Page 84 of 110

86 6.7 Poorly performing feeders SAIDI performance ratio The Code specifies that the SAIDI Performance Ratio 21 is used to determine whether an individual feeder has performed poorly in the current reporting period (clause 1.7.9). If the SAIDI Performance Ratio of an individual feeder exceeds the SAIDI threshold in at least two consecutive reporting periods (including the current reporting period), the feeder is considered to be poorly performing. The Code stipulates that the SAIDI threshold will be set as directed by the Commission. Power Networks has not received a SAIDI threshold from the Commission, and in the absence of this and with a best endeavours approach to reporting, Power Networks has adopted these performance thresholds from a major Eastern seaboard utility (Table 23). Table 23 - SAIDI threshold for poorly performing feeders by feeder category Feeder Category SAIDI Threshold (mins) CBD 2.5 Urban Rural Short 3.33 Rural Long 2.0 There were no feeders that performed poorly during that also performed poorly in , and therefore there are no poorly performing feeders covered by this section Performance improvements ( ) The Power Networks Feeder Upgrade Program is an annual program that uses five calendar years of interruption data to analyse outage causes for poorly performing feeders. Planned upgrades for poorly performing feeders are aimed at reducing the SAIDI, frequency and/or duration of outages depending on which indicator threshold has been breached. Upgrade plans are based on data that includes the most current information. The data is analysed in calendar years, which means performance up to and including December of any given year being analysed and actioned in plans that will commence in the following July. This can result in some feeders being classed as poorly performing in the financial year data but not in the 21 SAIDI Performance Ratio = (SAIDI Performance of Individual Feeder)/(SAIDI Target Standard of Individual Feeder s Feeder Category) Page 85 of 110

87 calendar year. Despite this any feeder identified in the financial year data as poorly performing is included in next year s feeder upgrade program in addition to those identified in the calendar year Upgrade actions Improving feeder performance involves a range of options determined by analysis of the cause and location of outages. The following section outlines a number of typical actions that are employed to address poor feeder reliability. Air Break Switch to Gas Break Switch changeovers Air Break Switches (ABS) are changed over to remotely controlled Gas Break Switches (GBS) in strategic locations to improve interruption restoration times. Poorly performing feeders with high interruption durations are targeted in this type of activity. ABS defects include jamming, burnt bridges and misalignment of arc chutes. The changing out of ABS to GBS reduces maintenance requirements as these common defects are engineered out in the GBS. Strategic replacements in each region are being identified in the feeder upgrade program. In addition, strategic change outs are being identified based on asset condition stemming from inspection and defect information in the Power Network Maintenance Plan. Hardware upgrades Hardware upgrades include the replacement of older pin insulators with more robust post type insulators. The post insulators provide better clearances and improve the lightning performance of the line. In addition, post insulators facilitate the installation of animal guards that minimise animal interference. Hardware upgrades also include the installation of fibreglass cross arms which are non-conductive, improve the lightning performance of the line and minimise interruptions due to animal interference. This type of cross arm is also used to replace wooden cross arms which are susceptible to rotting and subsequent failure. Animal guards are installed as a part of hardware upgrades on a feeder, with two types in use. The preferred is an electrostatic guard typically used for post insulators whilst the other is a plate animal guard and is used when the electrostatic guard cannot be fitted. Hardware upgrades also include the upgrade of backbone HV bridge connections having PG clamp or Live-line clamps which cause failure or open bridges and supply interruption. The clamps are to be replaced with permanent spliced connections which will reduce the longer duration outages. Furthermore, for poor performing feeders at problem areas, fault indicators are to be installed on overhead lines at regular intervals on the backbone feeder and on spur lines to aid in early fault identification and early restoration. There is also a trial Page 86 of 110

88 installation of a new type of switchgear planned which aims to reduce fault interruption duration on customers for transient faults that occur on spur lines. Network reconfigurations including GCR installation On poorly performing feeders prone to transient faults caused by vegetation, weather and/or animals, auto-reclosing at key network locations reduces outage and restoration times through better sectionalisation and remote operation. Gas Circuit Reclosers (GCRs) also improve restoration times by allowing the immediate reconfiguration of the network after an interruption from an adjacent feeder. GCRs are being installed on selected poorly performing feeders with a high number of transient faults and long outage durations. Underground cable monitoring and replacement High voltage cables are tested and condition assessed to determine if replacement is required. In addition, cables with more than three failures are scheduled for a condition assessment and/or replacement. These actions subsequently reduce the number of cable failures occurring in the system. Poorly performing feeders with a high incidence of cable failures have been targeted for priority testing and replacement programs. Even though there are no poorly performing feeders for the current reporting period, the above actions are applied to specific feeders as part of feeder upgrade programs for Service quality Power Networks receives information about the performance of the network through a number of data sources including customer notification of events and by network monitoring systems. Customer notifications regarding power outages or power quality are logged through the Power and Water Call Centre or website. Call out crews are assigned and investigate service requests due to upstream feeder faults, requests for the isolation of power and other requests resulting from power outages. The number of Power Network Customer Notifications is shown in Table 24. Table 24 - Customer notifications relating to quality of supply Region Fluctuating Low Power Part Power No Power Total % Total % Total % Total % Darwin 259 5% 114 2% % % Katherine 19 3% 10 2% % % Tennant Creek 7 5% 6 4% 16 11% % Alice Springs 33 6% 15 3% % % Page 87 of 110

89 The Code specifies the reporting of customer complaints into two main categories - Network Related Activities and Quality of Supply. Power Networks will further segment these main categories into sub categories used to report on the number of customer notifications within the business. The number of network related customer complaints is shown in Table 25. Table 25 - Number of customer complaints Network Related Activities Region Metering Reliability Damage to Other property/graffiti Total % Total % Total % Total % Darwin 15 12% 41 33% 13 11% 54 44% Katherine 1 50% 1 50% Tennant Creek 1 50% 1 50% Alice Springs 1 14% 2 29% 4 57% The Code nominates reporting on the number of written enquiries and average response times. This is shown in Table 26. Table 26 - Average time taken to respond to a customer s written enquiry segmented into regions Region Darwin Katherine Average time taken to respond to a customer s written enquiry (days) Tennant Creek 1 Alice Springs Comments There were a total of 129 written enquiries received and reported back to customers in There were a total of 2 written enquiries received and reported back to customers in There were a total of 3 written enquiries received and reported back to customers in There were a total of 7 written enquiries received and reported back to customers in The Code nominates reporting on the percentage and total number of new connections not undertaken within the specified time limit (Table 27). Page 88 of 110

90 Table 27 - Percentage and total number of new and re-connections not undertaken Connections Total % of Total not Undertaken New connections not undertaken in CBD/urban areas within 5 days New connections not undertaken in rural areas within 10 days % % In addition, the Code specifies reporting on the number and average length of time taken for new connections in the urban areas to new subdivisions as shown in Table 28. Table 28 - Number and average length of time taken to provide new connections in urban areas Connections Total Average length of time New connections in urban areas to new subdivisions weeks 6.9 Low voltage quality The Australian Standard AS (2001) specifies the limits of supply at a customer connection point. These limits are indicated in Figure 47 by the pink and yellow regions. Data for was assembled from available sources including package substation meters and specifically logged substation data. This does skew the results as substations that are specifically logged through the year tend to be due to a customer query regarding quality of supply. Data used was from 20 substations across Darwin (10), Alice Springs (6) and Katherine (4). It includes a mix of residential (9) and commercial (11) connections. For residential connections with low voltage runs, an assumed two per cent voltage drop was included to give a value closer to that at the customer connection point. The sites were generally logged for between three and seven days, with measurements averaged over 10 minute intervals. From Figure 51 it can be seen that 99 per cent of measured voltages were within the acceptable region, and 50 per cent were within the preferred operating zone. No measurements were found below the V 1% (216V) limit. The V 99% (253V) condition was also satisfied with only 0.69 per cent of voltage measurements exceeding 253V. Where logged substations have found to have high voltages, transformer tapping have been adjusted. Page 89 of 110

91 Figure 51 - RMS voltage distribution histogram for commercial & residential connections Going forward, this data will continue to be improved with all new interval meters purchased to be programed to measure voltage and sags as required by the Australian Standard AS These meters are installed at the customers end and also in all new package substations. Page 90 of 110

92 7 BUSINESS PERFORMANCE IN 2013/14 This section discusses aspects of Power Networks performance in 2013/ Capital program A summary of the major capital achievements realised in 2013/14 are: The second 38MVA 66/11kV transformer and 66kV indooor Gas Insulated Switchgear (GIS) has been commissioned at Frances Bay Zone Substation to further enhance supply to Darwin s CBD; construction for the new Leanyer Zone Substation is complete to cater for load growth for the new suburbs of Lyons and Muirhead; and the construction for the new CBD Darwin Zone Substation is complete to replace the ageing City Zone Substation; Figure 52 New Manton 22kV Indoor Switchroom 7.2 Maintenance program Maintenance completion reporting covers the three areas detailed in section 5.3: Preventative Maintenance, Planned Corrective Maintenance, Unplanned Corrective Maintenance and Specific Maintenance. It has taken a consistent effort to move the focus from a predominately Corrective Maintenance culture to one where Preventative Maintenance is acknowledged as critical. The power network is up to the challenge of striking the right balance between preventative, corrective and replacement works. While the identification and prioritisation of work was being performed adequately the process of managing work was identified as one that would yield significant benefits through improvements. The Work Management (WM) process was the focus of a great deal of effort which commenced late in and will continue in A project to improve the networks WM capability is being undertaken that leverages Maximo s core functionality to deliver improved works planning and a locked schedule for planned Page 91 of 110

93 works for 6 weeks. While the project leverages Maximo s capability it is not software driven. It focuses on the business structure and processes required to deliver the various work classifications and identifies where and how this is support by the application. This results in greater clarity of the work, its ownership and feedback on completion which are all important motivating factors in work completion. The project has required a high level of engagement with current work managers and reducing the time that they have for daily planning activity. This short term reduction of current planning capacity is a worthwhile investment that will ensure the ultimate success and long term sustainability of the project. The full should be realised in where the improved scheduling capability will result in less rework and greater labour utilisation and efficiencies. It is well understood that completion of a well-considered Preventative Maintenance Plan will result in reduced Corrective Maintenance. Assets failures that require corrective action divert resources from the preventative plan in a spiral that could return the organisation to a run to fail mentality if the correct focus is not provided. Although Power Networks still has a high number of defects, it has correctly focused its efforts on Preventative Maintenance where great improvements can be seen. The completion rate for Preventative Maintenance and backlog has been sustained through (Figure 53). The carry-over of uncompleted Preventative Maintenance Work Orders (backlog) was reduced from 399 in to 214 in The overall PM completion is pleasing, particularly given the commitment required by WM project. Ultimately it is the benefits that will be delivered through the WM Project that will allow all work to be completed on time and further improve PM completion. 100% Preventative Maintenance Performance 90% 80% 70% 60% 50% 40% PM Completion Backlog Completion Figure 53 - Preventative Maintenance completion against target ( ) The sustained Preventative Maintenance completion rate, along with Power Networks capital replacement program, is expected to yield reductions in the Page 92 of 110

94 volume of corrective work over that experience in recent years. The measurement of corrective maintenance is not detailed enough to determine if the balance between preventative and corrective maintenance is optimal. Historically, management of corrective work has resulted in poor data quality. The information that flows from this activity is critical to the function of managing the assets and efforts are being made to improve this area of the business. The majority of CM tasks are found as a result of Preventative Maintenance inspections. These are prioritised and actions pursued to avoid functional asset failure. Further improvements are required to establish CM processes that are supported by systems. The areas of improvement include refined failures classification codes, greater opportunity to batch work by classification and location The greatest opportunities to record the correct failure presents itself when the work is being performed in the field. The recently developed mobile application allows this task to be completed with the minimum of effort and increased accuracy thereby reducing ambiguity for downstream asset and work managers. Mobility also allows maintainers access to work orders and service requests that are current for each asset. Access to this information during the PM process provides an opportunity to check if known failure modes have further deteriorated and prevents work orders or service requests being re-flagged thereby eliminating duplicates. These initiatives improve the quality of information held on the asset base leading to higher definition of risks and greater opportunities to target work to provide improvements. The table below specifies the 2013/14 maintenance expenditure by maintenance type. Table /14 Maintenance expenditure by maintenance type Regulated Network and Standard Control Services Maintenance type 2013/14 expenditure Preventative Maintenance Planned Corrective Maintenance Unplanned Corrective Maintenance Total maintenance $14.9 M $9.2 M $12.1 M $36.2M Page 93 of 110

95 PART B: NETWORK DEVELOPMENT This Part of the Network Management Plan provides detailed information regarding the capability and development planning of Power Networks regulated electricity supply network. Part B is also intended to facilitate a process of public consultation and stakeholder feedback on network constraints, supply issues and proposed solutions and thereby provide awareness of potential investment opportunities which may be cost effective in avoiding or postponing network expansion. This document provides: network capacity information and load forecasts; identification of network limitations; augmentation works scheduled to undergo public consultation; analysis, options and potential projects; and opportunities for non-network solutions. The information in this document is based on the data available at the time of compilation. In addition, specific projects and works contemplated in this document, unless expressly stated as already being committed, represent Power Networks intention. All projects and works remain subject to: approvals, including Power and Water Board approval where applicable; specific detailed review at the time of all relevant factors including actual load growth, plant condition, relative priority and resource availability; and review against the requirements of the National Electricity Rules (Capital Expenditure Objectives and Criteria). Page 94 of 110

96 8 TRANSMISSION AND ZONE SUBSTATION DEVELOPMENT The following describes Power and Water s current plans for the development of its networks. Planning for the development of the network is an evolving process and as new information on customer and generator connections emerges, plans are adapted to ensure that the network is developed at the least overall cost to customers. The discussion in this section covers three aspects of planning for the future development of the network: emerging network constraints, anticipated to arise during the next five to ten years, with an indication of possible responses; longer term development strategies that are being progressively refined. These are encapsulated in the system master plan, which is updated annually or as required; and major network augmentations and replacements, planned to take place within the next five years. These form an integral component of the longer term strategies above. Appendix A2 contains information on the capacity of transmission circuits and the maximum flows anticipated under normal and credible contingency conditions. Similarly the Zone Substation Capacity Report in Appendix A3 outlines expected peak demand, cyclic and contingency cyclic ratings, available peak load transfers and the security level required and achieved. 8.1 Network Development Strategies kV and 66kV systems The major sources of generation for this system are at Channel Island and Weddell. 132kV lines connect Channel Island and 66kV lines connect Weddell to zone substations in the Darwin area. The 132kV system extends to Katherine, with generation connected at Pine Creek. The cyclone resistance of the existing 132kV lines will be improved at their most vulnerable point with the construction of a new double circuit crossing at the Elizabeth River and reconnecting one of the existing lines. This is scheduled to be completed before the 2016/17 wet season. As demand in Darwin and surrounds increases, the location of new generation will drive future transmission planning. Current load forecasts indicate that the existing 132kV transmission circuits will be adequate to meet demand for the next 10 years. The supply to the Pine Creek/Katherine region is currently via a single 132kV line with backup from generation at Katherine and Pine Creek. The existing 10 year forecast indicates there is no requirement for further development of this system. Page 95 of 110

97 8.1.2 Rural 66kV systems Humpty Doo Zone Substation and the rural system that extends to Mary River are supplied by a single 66 kv, 15MVA overhead line that is not cyclone coded. Power Networks is upgrading the 22kV rural network to provide an alternative supply to all customers fed from the Humpty Doo Zone Substation Metropolitan 66kV systems From the transmission system contingency analysis, attached in Appendix A2 the loss of the Weddell-McMinns 66kV line will result in the Hudson Creek Palmerston line exceeding its thermal limit. It is therefore required to construct a third 66kV transmission line to Palmerston from Archer Zone Substation. Construction of the new line is scheduled for 2017/ Darwin CBD supplies Power and Water s security standards for the supply to Darwin CBD require a timely response to a second contingency to the load area. This is the driver for a number of augmentations in the area. In the short term, a second transformer has been commissioned at Frances Bay Zone Substation. With the concurrent redevelopment of City Zone Substation, this will provide adequate transformer capacity to the CBD well beyond the current 10 year planning horizon Alice Springs system The demand in the Alice Springs area continues to grow at a low rate and the network is capable of meeting demand with the current arrangement. Changes to the generation arrangement in Alice Springs, such as the decommissioning of existing plant at Ron Goodin Power Station, may see the need for substantial changes to the transmission network. At this stage, if the capacity of the Ron Goodin Power Station is significantly reduced a third 66kV line to Sadadeen Zone Substation will likely be required. Further planning studies to identify the most appropriate strategy have not been included in Power Networks expenditure due to the uncertain nature of future generation development plans year master plan The diagrams which form the basis of the 10 year Master Plan are included in Appendix A1 10 year Master Plan. For the Darwin-Katherine system the main assumption for the expansion of the 132kV transmission system is that further generation expansion will occur at Weddell. On this basis two 132kV transmission lines will need to be constructed between a new 132kV bus at Weddell and a new 132/66kV terminal station located at Woolner on the old Snell St Zone Substation site. Although current load forecasts indicate that no further 132kV transmission is Page 96 of 110

98 required the 10 year master plan has assumed additional generation will be built at Weddell within the next 10 years. 8.3 Forecast capital program The five year capital program was developed on the basis of compliance with the planning criteria, objective need, risks and resource capability to deliver. This section outlines the capital investment program for and the following four years. A summary of the major projects capital spend and the individual minor capital projects are listed in the table below. Table 30 Forecast capital expenditure Project ($M) 2014/ / / / /19 Total major projects Capital Items and Essential spares Asset Replacement and Upgrade Programs HV Cable Replacement Program ORMU Replacement Program Feeder Upgrade Program Customer Augmentation and Network Extension Program SCADA and Communication Systems Replacement and Upgrade Program Protection Upgrade Program Meters/Metering Program Customer Connection Program Underground Distribution Substation Replacement Program Fully Funded Projects Total Capital Expenditure Power Networks capital investments reflect the need to replace network system assets, the need to improve network reliability and quality of supply, and the need to augment the network to meet the Northern Territory s growth in demand. Page 97 of 110

99 Fundamental to improving the condition and performance of the power network is the need to continue with the replacement of zone substations. Snell Street Zone Substation has been replaced with the new Woolner Zone Substation and the construction of the new Darwin Zone Substation to replace City Zone is complete. Construction of the Strangways Zone Substation to replace McMinns Zone Substation is well underway with the remaining Berrimah, Humpty Doo and Casuarina Zone Substation replacement works to be completed in this Network Price Determination (NPD) period. Additionally to meet demand growth, augmentation of Frances Bay with a second 38MVA 66/11kV transformer and commissioning of Leanyer Zone Substation and Wishart Modular Substation will occur in the 2015 year. The planned capital works will provide long-term engineering solutions to increase supply security and reliability and meet increased demand. 8.4 Major capital projects Below is a brief outline of Power Networks major capital projects, either currently under construction or forecast. Darwin: Construct Archer to Palmerston 66kV Transmission Line The current standard weather maximum demand load forecast for the Darwin region indicates an expected growth rate between 1.7 per cent and 2.4 per cent in the long term. A disproportional amount of this growth is expected to occur in the Palmerston and rural areas of Darwin. The transmission utilisation and contingency analysis indicates that constraints on existing transmission lines may occur as early as 2015/16. To alleviate these constraints, the construction of a new transmission line between Archer and Palmerston Zone Substation is undergoing development. Failure to address this problem will result in transmission line sections under contingency conditions (i.e. the loss of another transmission line during peak demand periods) exceeding thermal ratings. Under this condition the system controller would be required to shed load. Darwin: Construct Wishart Modular Substation Power Networks has closely monitored the commercial and industrial development of the East Arm area over the last 10 years as indications of significant development in the area have grown. During this time construction of additional power infrastructure has been deferred until substantial development was underway and subsequent load growth was evident. Recent investments in the gas industry and associated industries, such as marine support, have provided the strongest development signs to date and a number of companies have now been established in the Darwin Business Park, situated in East Arm, and the surrounding area to take advantage of the nearby rail and port infrastructure. The East Arm area is currently expanding at a modest rate. However it has the potential, with short notice, to grow substantially and beyond Power Networks current system capabilities with the addition of just one or two new major industrial customers. Page 98 of 110

100 The East Arm area is currently supplied with power from Berrimah Zone Substation. The firm capacity of Berrimah Zone Substation has already been exceeded and the area load security is maintained during peak times through an ability to transfer other loads to Palmerston Zone Substation. This option is becoming increasingly limited as load increases at the Palmerston Zone Substation. In addition to the constraints at Berrimah Zone Substation, the high voltage feeders in the East Arm area are also approaching the 11kV feeder N-1 firm capacity and can experience low voltage during contingency conditions. Additional to this the Government has announced that the Berrimah farms area will now be fast tracked as a major residential development. Given the capacity limitations of the existing systems and the potential for additional growth, it is prudent to progress this investment option now. The proposed solution is to install an interim modular substation in the near term to ensure demand can be met. This will defer the requirement to build a new zone substation to the next regulatory control period. A substantial portion of this interim solution is the civil and electrical works for the 11kV feeder connections, which would be re-routed at minimal cost to the adjacent zone substation site. Failure to proceed with the interim solution will expose Power Networks to a situation in the short term where it would be unable to meet new customer loads in the East Arm and Berrimah areas. Construction has been completed for the new modular substation including feeder connections. The substation is due for commissioning in the first half Darwin: Strangways 66/22kV Zone Substation (replace McMinns Zone Substation) McMinns Zone Substation was constructed in the 1970s and is now aged and in poor condition. The outdoor 66kV and 22kV switchgear are at the end of their serviceable life. These assets have a significant impact on network reliability and maintenance costs are continuing to increase in an effort to keep them in service. This zone substation is critical to the supply of power to Darwin s rural area. Construction of the new Strangways Zone Substation has commenced to replace the McMinns Zone Substation. Construction is due for completion July 2015 with commissioning late Darwin: Replace Casuarina 66kV Outdoor Switchyard Casuarina Zone Substation has in recent years experienced a number of major asset failures resulting in significant outages. While the 11kV equipment has been replaced, the 66kV switchgear is now over 40 years old with the circuit breakers having industry known reliability concerns. The transformers are also nearing end of life and are generally in poor condition. This project involves the installation of indoor 66kV Gas Insulated Switchgear (GIS) in a new building and three new 20/27MVA 66/11kV transformers to replace all Page 99 of 110

101 existing outdoor 66kV switchgear and transformers. Construction is expected to commence mid 2015 with commissioning first half of Darwin: Replace Berrimah Zone Substation Berrimah Zone Substation was commissioned in the late 1970s and many of the assets that are currently installed are approaching the end of their serviceable life. In particular, the 66kV switchyard consists of five ASEA HLC minimum oil breakers similar to those located at Casuarina and McMinns Zone Substations, with the same reliability concerns. The power transformers are in an aged condition with high moisture levels, a history of oil leaks and poor oil furan test results, indicating they are nearing end of life. Replacement of the switchboard is also recommended as it is not arc rated and does not have any busbar protection scheme, therefore posing safety concerns for operational staff. This project is not due for construction until the end of the regulatory control period and is currently undergoing options analysis to determine the most prudent and cost effective solution. Alice Springs: Install Sadadeen 11kV Switchboard Power Networks currently share a common 11kV switchboard located at Ron Goodin Power Station, directly adjacent to the Sadadeen Zone Substation, with Territory Generation. This switchboard is considered to be at the end of its serviceable life. Territory Generation will be retiring generating plant in line with the expansion of the new Owen Springs Power Station, leading eventually to the closure of Ron Goodin Power Station. Power Networks is planning to relocate the 11kV feeders from Ron Goodin to a new switchboard located at the Sadadeen Zone Substation site prior to this closure and in consideration of the age and condition of the current Ron Goodin 11kV switchboard. This switchboard was commissioned in 1969 and in 2012 the oil circuit breakers were retrofitted with vacuum circuit breakers in response to the removal of oil switchgear following the failure at Casuarina Zone Substation. Despite these newer elements, the switchboard itself is still considered to be at its end of life and likely to experience an increased rate of failures. The installation of a new switchboard would be entirely for Power Networks distribution, the switchgear would be modern, have improved design for reliability, maintenance and operations as well as being safer, with features such as arc-containment. This project is required to maintain the quality, reliability and security of supply to the Alice Spring town centre via asset renewal. This switchboard feeds over half the load of Alice Springs. Installation of this switchboard will commence in the 2016/17 financial year. Page 100 of 110

102 Alice Springs: Replace Sadadeen 22kV Switchboard Power Networks had three Yorkshire YFS6 22kV switchboards located at Manton, Katherine and Sadadeen Zone Substations. This make and type of switchgear has a known design defect that results in high partial discharge levels that significantly reduces its original design life, particularly in areas of high humidity. There has been a high number of failures at both Katherine and Manton Zone Substations. In response to these failures the Yorkshire switchgear has been replaced at Katherine Zone Substation and switchgear replacement at Manton Zone Substation is expected to be complete by the end of The failure of the Yorkshire bus-section panel at Sadadeen Zone Substation in 2010 lead to the blackout of Sadadeen and Lovegrove Zone Substations over a six hour period and resulted in a review of the Sadadeen switchgear replacement program. A number of remedial and additional maintenance actions were immediately taken to ensure improved environmental controls of the site and maximise the life of the equipment, including water sealing of cables ducts and trenches, re-sealing of the concrete building, installation of continuous online partial discharge monitoring and the installation of a de-humidifier. While these actions have significantly slowed the partial discharge failure mode, the problems are inherent to the equipment and further failures will occur. As such, replacement of this board is recommended. This project will ensure a safe, reliable, high quality power supply for customers in Alice Springs, as well as enhancing operational safety and functionality. The installation of this switchboard will commence in the 2017/18 financial year. Darwin: Construct Leanyer Zone Substation and 66kV Line The residential development at Lee Point Peninsula has potential to increase demand by 40MVA in this area, requiring an additional zone substation. The first stage of this development, Lyons subdivision, is complete and the next stage, Muirhead, is currently under construction. The construction of this zone substation will also provide an alternative source of supply to areas currently supplied from the Casuarina Zone Substation. It will alleviate demand loading for Casuarina Zone Substation and allows possible contingency loading at Berrimah and Woolner Zone Substations. Construction of Leanyer Zone Substation is complete will commissioning mid Integrated Distribution Management System (IDMS) The IDMS will provide additional productivity, capability and safety benefits across low voltage and high voltage network control, customer service, network planning and asset management, at a marginal additional cost. The IDMS will eventually allow a strategy of automated switching to restore customers after a fault and can also be used to shift load as a means of deferring capital spend. The IDMS Project will also establish the necessary systems for network reliability and customer notification performance level reporting required under the Page 101 of 110

103 Guaranteed Service Levels Code at a lower cost and higher level of accuracy than the alternative manual approach. It is planned to go to tender for a distribution management or operational management system (OMS) mid Tennant Creek Installation of 22kV Switchboard Tennant Creek Zone Substation is equipped with unreliable vacuum outdoor 22kV switchgear. The switchyard is very old, poses increased staff safety risk and has experienced numerous outages due to local birdlife perched on the outdoor system busbars. This project is to build an indoor 22kV substation and transfer the associated circuits to the vacuum breakers in a new switchroom. The existing outdoor switchyard will be decommissioned. Commissioning of the new indoor switchgear is planned for August Upgrade of CBD Switching Stations Most of the 11kV CBD switching stations are equipped with ageing oil filled 11kV switchgear. This equipment is nearing the end of its serviceable life and presents a high risk of fire damage in the event of failure. The switchgear at Woods Street, West Bennett Street, Mott Street and Austin Knuckey switching stations will be progressively replaced with modern indoor vacuum circuit breaker switchboards. The switchgear at Woods Street was replaced with works proceeding this financial year at Mott Street. The remaining switchboards at West Bennett and Austin Knuckey will be replaced over the 2015/16 and 2016/17 financial years. Rebuild the Channel Island Power Station to Hudson Creek 132kV Transmission Line Elizabeth River Crossing (PRD30003) The existing 132kV tower lines from Channel Island Power Station and the 66kV lines from Weddell Power Station to the Darwin area have been identified as structurally inadequate to withstand a low end Category 3 cyclone. If an event of this nature were to occur, the transmission lines would potentially suffer major damage that could take weeks to repair. Works to strengthen the 66kV transmission system between Weddell and Darwin have been completed. However approximately half the Darwin-Katherine demand would remain at risk for failure of the 132kV transmission system between Channel Island Power Station and Hudson Creek Terminal Station. In the event that the 132kV transmission circuits to Darwin were both damaged during a Category 2/3 cyclone, the economic impact on the Northern Territory would be substantial. Therefore a section of new 132kV double circuit transmission line designed and built to Category 4 cyclone winds spanning the Elizabeth River is recommended to be constructed. A tender has been released for this project with final commissioning planned prior to the 2016/17 wet season. Page 102 of 110

104 8.5 Minor Capital Programs for Asset Replacement Refer to Appendix 5 for quantity of asset replacements for the programs described below. High Voltage Cable Replacement Program Analysis of system reliability shows that the contribution of High Voltage (HV) cable failures to system SAIDI is disproportionally high and requires a targeted replacement program to reduce this to an acceptable level. XLPE aluminium cables installed in the early 1980 s are known to industry as being particularly susceptible to moisture ingress, corrosion and subsequent failures. There is approximately 143 kilometres of this type of cable installed around this time. The planned expenditure for the next five years aims to replace nine kilometres of cables that have been shown by testing to be in extremely poor condition. This expenditure is based on the actual per metre cost of replacing a faulty cable in the northern suburbs. Installed cables will continue to be condition assessed using specialised testing techniques and equipment to determine cables that are in poorest condition. Oil Ring Main Unit (ORMU) Replacement Program It is generally accepted within the power distribution industry that operation of aging ORMU s presents a high risk to personnel and the public due to the consequences of a failure to anyone in the vicinity of the equipment. Many ORMU s are located in public areas such as lane ways, parks and road reserves. Most units have been in service for greater than 30 years, and have an average age of 42 years. Prioritisation of units is based on their location i.e. whether in public areas and their condition. Until these ORMUs are replaced they are condition assessed as part of the preventative maintenance plan and corrective action taken where required. Some ORMUs are installed at critical switching points in the power network and are unable to be modified to allow future automation or fault indication. These units have been identified and considered when prioritising the replacement program. As these units are replaced with modern automated equivalents the network reliability will improve due to the opportunities to fault find and reduce restoration times. Feeder Upgrade Program The SAIDI target standards represent the acceptable level of reliability for the network. These standards are set in the Electricity Standards of Service (ESS) Code published by the Commission. An improvement target of five per cent has also been set by the Commission. Each year Power Networks analyses the performance of all feeders with a particular focus on those feeders that are not meeting the required standards of service. The Page 103 of 110

105 analysis uses five years of historical outage data and considers the types of interruption. The outcome is a targeted feeder upgrades planned for the upcoming financial year. Section describes the common upgrade actions for poorly performing feeders. Feeder performance is continuing to be monitored to determine the success of the feeder upgrades and improvement works. The trend in overall performance is also compared to the standards set in the ESS code to ensure the required five per cent improvement is achieved. SCADA and Communication Systems Replacement and Upgrade Program Based on the asset classes a replacement or upgrade program has been developed to ensure the continued and reliable operation of these critical assets as well as ensuring the required functionality of the assets is provided. The Operational Telecommunications Network provides critical links for Protection, SCADA and other operational services such as the 2 Way Radio system. Power Protection Upgrade Program Many of the existing power protection systems have been in service for more than 20 to 30 years. These electromechanical, solid state and the early microprocessor based relays are now out of production and replacement units or spare parts are unavailable. These relays that are installed in our network are approaching their end of life evidenced through failures during preventative maintenance testing. The combination of failing assets and difficult or unobtainable spare parts provides challenges for the management of these assets in our network and makes the replacements in this asset class important. The Zone Substation and Switching Station replacement activity described above (section 8.4) provide the majority of replacements for this asset class. Advances in protection relay technology have been significant over recent years and have resulted in enhanced relay functionality. The replacement activity has triggered a review of the Power Networks protection philosophies so as to exploit the enhanced functionality of the current generation of protection devices. Despite the work outlined above there are still sites where aged protection relays are in service and major primary plant replacements are not imminent. An additional replacement program has been developed for these devices to sustain the reliability of this asset class. Page 104 of 110

106 Underground Distribution Substation Replacement Program Distribution substations in the underground network that are reaching end of life are not economical to repair. The condition of substations, particularly in the Darwin region, is greatly affected by the high humidity and salty environment. Many of the units reaching an age of years have significant corrosion that results in oil leaks which are not economical to repair. High Voltage switchgear used in these older substations is also difficult to maintain due to age and provides lesser protection to operators under fault conditions. The estimated quantity of replacements in future years as shown in Appendix A5 is based on 20 per cent of the asset pool exceeding 40 years in service. Additional units have been identified for replacement in 2014/15 due to developing faults identified through oil sampling. Asset Replacement and Upgrade Programs Any asset replacements identified that are not part of a large replacement program of a value greater than $5 million over five years are included in the Asset Replacement and Upgrade Program. The program includes specific assets, asset classes or types that have reached end of life or are found to have significant operational or safety defects and require replacement or augmentation. Other network safety and reliability improvements may also be identified requiring capital investment to mitigate risk to personnel and the public. Page 105 of 110

107 APPENDIX 1 10 YEAR MASTER PLAN Page 106 of 110

108 132 kv 66 kv CIPS 132 WD new 132kV new 66kV AP Air Port BA Batchelor BE Berrimah CA Casuarina CH Cosmo Howley CIPS Channel Island PS CZ City Zone CP Cox Peninsula FB Frances Bay HC Hudson Creek HD Humpty Doo HS Howard Springs KA Katherine LE Leanyer MK Mataranka MM McMinns MT Manton PA Palmerston UR Union Reef WD Weddell WN Woolner WPS Weddell Power Stn WS Wishart G A 2016 B HC132 G HC66 CP CZ WN132 future FB Darwin Katherine System 10 year Master Plan WN66 CH BA MT G MM HD MK BE 2020 LE 2015 CA 2025 AP 2024 UR PC132 WPS HS 2022 PA G PC66 G KA132 AR 2019 WS 2021 WS 2015 WS 2015

109 Lovegrove 11kV 10-Year Alice Springs System Development Plan T1,T2 upgrade G Lovegrove 22kV Sadadeen ZSS Rebuild 2018/19 Retire RGPS 11kV Sadadeen 11kV Lovegrove 66kV T3, G Brewer 1 Farm SD 66kV Airport Borefield OWPS 66kV OWPS 11kV Brewer 22kV 11kV 22kV 66kV future G G Brewer P/S Black Font - Current Green Font - Future G

110 APPENDIX 2 TRANSMISSION LINE UTILISATION/CAPACITY Page 107 of 110

111 Transmission Line DARWIN/KATHERINE SYSTEM TRANSMISSION CAPACITY UTILISATION 2013/ /24 Maximum Demand - Weather Corrected (MVA) From To Voltage (kv) Circuit Number Item 2013/ / / / / / / / / / /24 Project Programmed CIPS 132 CIPS 132 CIPS 132 Manton 132 Batchelor 132 Batchelor 132 Pine Creek 132 HC HC Manton Pine Creek Katherine 132 Woolner 66 Archer Archer 66 East Arm/Wishart 66 Hudson Creek 66 Berrimah 66 Hudson Creek 66 Berrimah 66 Hudson Creek 66 Woolner 66 Hudson Creek 66 Woolner 66 Hudson Creek 66 City Zone 66 Hudson Creek 66 Palmerston A B Maximum Demand Normal Rating Contingency Rating Utilisation 29% 34% 41% 43% 45% 45% 47% 50% 52% 53% 57% Maximum Demand Normal Rating Contingency Rating Utilisation 30% 35% 42% 43% 45% 45% 48% 51% 52% 53% 58% Maximum Demand Normal Rating Contingency Rating Utilisation 5% 6% 5% 5% 4% 4% 4% 4% 4% 4% 4% Maximum Demand Normal Rating Contingency Rating Utilisation 4% 5% 5% 5% 5% 6% 6% 5% 5% 5% 5% Maximum Demand Normal Rating Contingency Rating Utilisation 4% 5% 5% 5% 5% 6% 13% 5% 5% 5% 5% Maximum Demand Normal Rating Contingency Rating Utilisation 7% 9% 9% 9% 9% 9% 9% 9% 9% 9% 9% Maximum Demand 37.3 Normal Rating 64.0 Contingency Rating 80.0 Changed to Archer/East Arm 66 kv line Utilisation 58% Maximum Demand Normal Rating FROM Contingency Rating 2014/ Utilisation 14.1% 14.4% 14.7% 15.0% 15.3% 4.8% 2.8% 1.9% 2.5% 3.8% Maximum Demand Normal Rating Contingency Rating Utilisation 50% 46% 52% 52% 53% 55% 56% 57% 58% 59% 60% Maximum Demand Normal Rating Contingency Rating Utilisation 50% 46% 52% 52% 53% 55% 56% 57% 58% 59% 60% Maximum Demand Normal Rating Contingency Rating Utilisation 84% 83% 81% 83% 85% 88% 90% 93% 95% 98% 100% Maximum Demand Normal Rating FROM Changed to Hudson Creek/East Contingency Rating 2014/ Arm/Woolner 66 kv Line Utilisation 75.9% 74.5% 76.4% 78.6% 80.8% Maximum Demand Normal Rating Contingency Rating Utilisation 65% 66% 65% 67% 68% 70% 72% 74% 76% 77% 79% Maximum Demand Normal Rating Contingency Rating Utilisation 41% 42% 65% 51% 50% 44% 46% 50% 52% 54% 56%

112 Transmission Line Maximum Demand - Weather Corrected (MVA) From To Voltage (kv) Circuit Number Item 2013/ / / / / / / / / / /24 Project Programmed Maximum Demand Palmerston 66 McMinns Normal Rating Contingency Rating Utilisation 11% 12% 8% 13% 12% 2% 1% 2% 3% 4% 6% Maximum Demand Hudson Creek 66 Archer Normal Rating Contingency Rating Utilisation 38% 58% 47% 12% 13% 15% 8% 5% 3% 4% 6% Maximum Demand Archer 66 Weddell Normal Rating Contingency Rating Utilisation 41% 37% 34% 39% 43% 44% 33% 45% 46% 46% 47% Maximum Demand Archer 66 Weddell Normal Rating Contingency Rating Utilisation 47% 42% 39% 44% 49% 51% 52% 52% 52% 53% 54% Maximum Demand Hudson Creek 66 East Arm Normal Rating 64 To be disconnected (2014/15) and to be Contingency Rating 80 reconnected (2019/20) Utilisation 0% 95% 99% 102% 105% 108% Maximum Demand East Arm 66 Woolner Normal Rating To be connected on the year 2019/20 Contingency Rating Utilisation 83% 85% 88% 90% 91% Maximum Demand Berrimah 66 Leanyer Normal Rating Contingency Rating Utilisation 41% 42% 55% 57% 58% 59% 60% 62% 63% 64% 65% Maximum Demand Leanyer 66 Casuarina Normal Rating Contingency Rating Utilisation 41% 44% 24% 25% 25% 25% 26% 26% 27% 27% 27% Maximum Demand Casuarina 66 Woolner Normal Rating Contingency Rating Utilisation 35% 35% 26% 26% 26% 25% 25% 25% 25% 24% 24% Maximum Demand Woolner 66 City Zone Normal Rating Contingency Rating Utilisation 21% 28% 29% 29% 30% 30% 30% 30% 30% 30% 31% Maximum Demand Woolner 66 Frances Bay Normal Rating Contingency Rating Utilisation 19% 26% 27% 27% 28% 28% 28% 28% 28% 29% 29% Maximum Demand City Zone 66 Frances Bay Normal Rating Contingency Rating Utilisation 4% 19% 19% 20% 20% 21% 22% 23% 23% 24% 24% Maximum Demand Weddell 66 McMinns Normal Rating Contingency Rating Utilisation 49% 57% 65% 51% 54% 47% 47% 48% 49% 50% 50% Maximum Demand McMinns 66 Humpty Doo Normal Rating Contingency Rating Utilisation 19% 20% 20% 20% 20% 21% 21% 21% 22% 22% 22% Thermal rating is same as normal rating (cable) Thermal rating is same as normal rating (cable)

113 Transmission Line Maximum Demand - Weather Corrected (MVA) From To Voltage (kv) Circuit Number Item 2013/ / / / / / / / / / /24 Project Programmed Humpty Doo 66 Pine Ck ZSS 66 Mary River 66 Pine Ck Power Station Pine Ck Power Station 66 Union Reef Tee Union Reef Tee 66 Brocks Ck Tee Brocks Ck Tee 66 City Zone 66 Cosmo Howley 66 Centre Yard Archer 66 Palmerston Maximum Demand Normal Rating Contingency Rating Utilisation 13% 14% 14% 14% 14% 15% 15% 16% 16% 16% 16% Maximum Demand Normal Rating Contingency Rating Utilisation 17% 16% 17% 17% 17% 17% 17% 17% 17% 17% 17% Maximum Demand Normal Rating Contingency Rating Utilisation 49% 49% 50% 50% 50% 51% 51% 51% 51% 52% 52% Maximum Demand Normal Rating Contingency Rating Utilisation 15% 15% 15% 15% 15% 15% 15% 15% 15% 15% 15% Maximum Demand Normal Rating Contingency Rating Utilisation 15% 15% 15% 15% 15% 15% 15% 15% 15% 15% 15% Maximum Demand Normal Rating Contingency Rating Utilisation 6% 6% 6% 6% 6% 6% 6% 6% 6% 6% 6% Maximum Demand Analysis indicates new line Normal Rating is to be constructed on Contingency Rating /17 Utilisation 37.4% 39.1% 38.2% 37.4% 38.4% 38.7% 38.8% 39.1% New 66 kv line from Archer ZS to Palmerston ZS

114 TRANSMISSION CONTINGENCY - 1 DARWIN/KATHERINE SYSTEM TRANSMISSION CONTINGENCY ANALYSIS TRANSMISSION LINE DETAILS CONTINGENCY LOADING From To Voltage (kv) Circuit No. Status Item 2013/ / / / / / / / / / /24 Load Before Outage Load After Outage Hudson Creek 66 Palmerston Out of Service Contingency Rating Utilisation Before Outage 33% 34% 52% 41% 40% 35% 37% 40% 42% 43% 45% Utilisation During Outage 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% Load Before Outage Load After Outage Weddell 66 McMinns In Service Contingency Rating Utilisation Before Outage 39% 46% 52% 41% 43% 37% 38% 39% 39% 40% 40% Utilisation During Outage 75% 85% 114% 51% 53% 46% 47% 49% 50% 51% 52% Load Before Outage Load After Outage Palmerston 66 McMinns In Service Contingency Rating Utilisation Before Outage 9% 10% 6% 11% 10% 2% 1% 2% 3% 4% 5% Utilisation During Outage 40% 41% 54% 2% 1% 8% 8% 9% 9% 9% 9% Load Before Outage Load After Outage New line to be commissioned Archer 66 Palmerston In Service Contingency Rating between Archer and Utilisation Before Outage Palmerston 2016/ % 28% 29% 29% 29% 30% Utilisation During Outage 56.7% 57.1% 53% 55% 58% 59% 60% 61% TRANSMISSION CONTINGENCY - 2 Weddell 66 McMinns Out of Service Hudson Creek 66 Palmerston In Service Palmerston 66 McMinns In Service Archer 66 Palmerston In Service Load Before Outage Load After Outage Contingency Rating Utilisation Before Outage 39% 46% 52% 41% 43% 37% 38% 39% 39% 40% 40% Utilisation During Outage 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% Load Before Outage Load After Outage Contingency Rating Utilisation Before Outage 33% 34% 52% 41% 40% 35% 37% 40% 42% 43% 45% Utilisation During Outage 71% 79% 103% 59% 59% 52% 55% 59% 61% 61% 64% Load Before Outage Load After Outage Contingency Rating Utilisation Before Outage 9% 10% 6% 11% 10% 2% 1% 2% 3% 4% 5% Utilisation During Outage 32% 40% 51% 52% 53% 38% 39% 40% 41% 42% 43% Load Before Outage Load After Outage New line to be commissioned Contingency Rating between Archer and Utilisation Before Outage Palmerston 2016/ % 29.6% 33% 32% 33% 33% 33% 33% Utilisation During Outage 50.4% 52.7% 55% 53% 55% 55% 56% 56%

115 TRANSMISSION CONTINGENCY - 3 Hudson Creek 66 Berrimah OR 2 Hudson Creek 66 Berrimah OR 1 Woolner 66 Casuarina Out of Service In Service In Service Load Before Outage Load After Outage Contingency Rating Utilisation Before Outage 40% 37% 41% 42% 43% 44% 45% 46% 46% 47% 48% Utilisation During Outage 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% Load Before Outage Load After Outage Contingency Rating Utilisation Before Outage 40% 37% 41% 42% 0% 44% 45% 46% 46% 47% 48% Utilisation During Outage 75% 68% 76% 77% 79% 82% 83% 85% 86% 88% 89% Load Before Outage Load After Outage Contingency Rating Utilisation Before Outage 28% 28% 21% 21% 21% 20% 20% 20% 20% 19% 19% Utilisation During Outage 34% 34% 35% 28% 27% 28% 27% 27% 27% 27% 27% TRANSMISSION CONTINGENCY - 4 TRANSMISSION CONTINGENCY - 5 Hudson Creek 66 Woolner Out of Service Hudson Creek 66 Woolner In Service Hudson Creek 66 City Zone In Service Hudson Creek 66 Berrimah 66 1 & 2 In Service Woolner 66 Casuarina Out of Service Hudson Creek 66 Berrimah & 2 In Service Berrimah 66 Leanyer In Service Load Before Outage Load After Outage Contingency Rating Utilisation Before Outage 67% 66% 65% 67% 68% 70% 72% 74% 76% 78% 80% Utilisation During Outage 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% Load Before Outage Load After Outage FROM Will be changed to Hudson Creek/Wishart/Woolner Contingency Rating kv line Utilisation Before Outage 61% 60% 61% 63% 65% Utilisation During Outage 96% 94% 97% 99% 102.0% Load Before Outage Load After Outage Contingency Rating Utilisation Before Outage 52% 53% 52% 53% 55% 56% 58% 59% 61% 62% 63% Utilisation During Outage 86% 75% 74% 76% 78% 80% 82% 84% 86% 89% 91% Load Before Outage Load After Outage Contingency Rating Utilisation Before Outage 40% 37% 41% 42% 43% 44% 45% 46% 46% 47% 48% Utilisation During Outage 50% 43% 47% 48% 49% 51% 52% 53% 54% 55% 56% Load Before Outage Load After Outage Contingency Rating Utilisation Before Outage 28% 28% 21% 21% 21% 20% 20% 20% 20% 19% 19% Utilisation During Outage 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% Load Before Outage Load After Outage Contingency Rating Utilisation Before Outage 40% 37% 41% 42% 43% 44% 45% 46% 46% 47% 48% Utilisation During Outage 55% 52% 52% 53% 53% 55% 55% 56% 57% 57% 58% Load Before Outage Load After Outage Contingency Rating Utilisation Before Outage 33% 34% 44% 45% 46% 47% 48% 49% 50% 51% 52% Utilisation During Outage 62% 63% 66% 66% 68% 68% 69% 70% 70% 71% 71%

116 TRANSMISSION CONTINGENCY - 6 Berrimah 66 Leanyer Woolner 66 Casuarina Hudson Creek 66 Woolner Out of Service 1 & 2 In Service 1 In Service Load Before Outage Load After Outage Contingency Rating Utilisation Before Outage 33% 34% 44% 45% 46% 47% 48% 49% 50% 51% 52% Utilisation During Outage 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% Load Before Outage Load After Outage Contingency Rating Utilisation Before Outage 28% 28% 21% 21% 21% 20% 20% 20% 20% 19% 19% Utilisation During Outage 62% 63% 67% 68% 68% 69% 70% 70% 71% 72% 73% Load Before Outage Load After Outage Contingency Rating Utilisation Before Outage 67% 66% 65% 67% 68% 70% 72% 74% 76% 78% 80% Utilisation During Outage 86% 81% 84% 87% 89% 91% 94% 96% 99% 101% 104% TRANSMISSION CONTINGENCY - 7 CIPS 132 Hudson Creek or 2 CIPS 132 Hudson Creek or 1 Out of Service In Service Load Before Outage Load After Outage Contingency Rating Utilisation Before Outage 27% 31% 38% 39% 41% 41% 43% 45% 47% 48% 52% Utilisation During Outage 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% Load Before Outage Load After Outage Contingency Rating Utilisation Before Outage 27% 31% 38% 39% 41% 41% 43% 46% 47% 48% 52% Utilisation During Outage 57% 58% 63% 67% 70% 72% 76% 77% 79% 82% 84% TRANSMISSION CONTINGENCY - 8 Archer 66 Palmerston Hudson Creek 66 Palmerston Weddell 66 McMinns Palmerston 66 McMinns Out of Service In Service In Service In Service Load Before Outage Load After Outage New line to be commissioned Contingency Rating between Archer and Utilisation Before Outage Palmerston 2016/ % 43.8% 42.6% 44% 43% 53% 55% 55% Utilisation During Outage 0.0% 0.0% 0.0% 0% 0% 0% 0% 0% Load Before Outage Load After Outage Contingency Rating Utilisation Before Outage 41.1% 40.0% 35.4% 51% 57% 40% 41% 43% Utilisation During Outage 63.4% 63.3% 58.0% 61% 65% 67% 68% 70% Load Before Outage Load After Outage Contingency Rating NOT APPLICABLE Utilisation Before Outage 41.0% 43.0% 37.3% 49% 50% 59% 60% 61% Utilisation During Outage 51.4% 53.8% 47.8% 47% 48% 49% 49% 50% Load Before Outage Load After Outage Contingency Rating Utilisation Before Outage 10.8% 9.9% 1.5% 18% 23% 15% 15% 16% Utilisation During Outage 5.6% 5.6% 10.1% 8% 8% 7% 7% 7%

117 APPENDIX 3 TRANSMISSION TERMINAL STATION AND ZONE SUBSTATION UTILISATION/CAPACITY

118 ZONE SUBSTATION / TRANSMISSION TERMINAL STATION / MODULAR SUBSTATION VOLTAGE (kv) INSTALLED CAPACITY HISTORICAL FORECAST NUMBER OF ITEM TRANSFORMER SIZES (MVA) / / / / / / / / / /2019 TRANSFORMERS COMMENTS Darwin Katherine Archer zone substation 66/ /27 P (50) standard weather maximum demand (MVA) A load of MVA was transferred from the Palmerston zone substation on a permanent basis Actual maximum demand (MVA) A load of MVA will be transferred from the Palmerston zone substation on a permanent basis. 1 Normal rating (MVA) ) A new load of MVA will be connected. 2.) A new load of MVA will be connected. Normal cyclic rating (MVA) A new load of MVA will be connected. Contingency cyclic rating (MVA) Peak load temporary transfer (MVA) Load can be transferred to the Palmerston zone substation (66/11 kv). Generation (MW) Normal utilisation (%) 31% 31% 44% 46% 62% 68% 70% Contingency utilisation (%) 62% 62% 89% 92% 124% 137% 140% Required class of supply C C C C C C C Actual class of supply C C C C C* C* C* * Class of supply 'C' maintained via transfer. Batchelor zone substation 132/ /27 P (50) standard weather maximum demand (MVA) stage shutdown ( MVA) for Brown Oxide mine Temporary Switching: 3.5 MVA to 5 MVA peak considered from charted peaks. Actual maximum demand (MVA) Manton zone substation was out of service during the year 2013/ MVA temporarary load transfer from the Manton zone Normal rating (MVA) substation has been assumed. Normal cyclic rating (MVA) Contingency cyclic rating (MVA) ) Load can be transferred to the Manton zone substation in the first instance. 2.) Load can be transferred to the McMinns zone substation via Manton zone substation feeders, if the Manton zone substation is Peak load temporary transfer (MVA) out of service. Generation (MW) Normal utilisation (%) 20% 28% 6% 9% 6% 10% 6% 5% 4% 4% 3% Contingency utilisation (%) N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A Required class of supply G G F F F F F F F F E Actual class of supply * G G F F F F F F F F F * Class of supply 'F' and 'G' maintained via transfer ) 1 MVA load was disconnected from the Berrimah zone substation. 2.) A load of MVA was transferred to the Casuarina zone substation on a permanent basis. Berrimah zone substation 66/ /31.5/38 P (50) standard weather maximum demand (MVA) ) A new load of 1.5 MVA has been connected. 2.) A new load of 0.23 MVA has been connected. 3.) A new load of MVA has been connected. 4.) A load of MVA has been transferred from the Casuarina zone substation on a permanent basis. 5.) A load of MVA has been transferred to the Casuarina zone substation on a permanent basis. Actual maximum demand (MVA) ) A new load of 1 MVA will be connected. 2.) A new load of 1.8 MVA will be connected. Normal rating (MVA) ) 9 MVA load will be transferred to the Wishart modular substation on a permanent basis ) A new load of MVA will be connected. 2.) A load of MVA load will be transferred to the Leanyer zone substation on a permanent basis. Normal cyclic rating (MVA) Contingency cyclic rating (MVA) A new load of MVA will be connected. 15 The cyclic rating of existing 25/31.5/38 MVA transformer is limited to 38.1 MVA, due to 11kV circuit breaker rating 2000A. Peak load temporary transfer (MVA) ) The existing 2 x 25/31.5/38 MVA transformers will be replaced with 3 x 20/27 MVA transfomers. 2.) 11 kv transformer circuit breakers to be replaced to appropriate rating. Generation (MW) ) Normal cyclic ratings have been assumed to be the same as the normal ratings. Normal utilisation (%) 50% 50% 48% 50% 45% 44% 43% 40% 41% 41% 41% 17 The load can be supplied via non-network solution (Generation). 18 The installed capacity of generators is 10 MW (2 x 5 MW). Contingency utilisation (%) 101% 101% 95% 99% 91% 89% 86% 81% 82% 83% 61% Required class of supply C C C C C C C C C C C 19 Berrimah generation not available from 2011/2012 onwards. Actual class of supply C* C* C C C C C C C C C * Class of supply 'C' maintained via non-network solution (Generation). Brocks Creek zone substation 66/ P (10) weather corrected maximum demand (MVA) The Brocks Creek zone substation was decommissioned in 2014/2015. Actual maximum demand (MVA) Normal rating (MVA) Normal cyclic rating (MVA) Contingency cyclic rating (MVA) Peak load temporary transfer (MVA) Generation (MW) Normal utilisation (%) 18% 19% 32% 1% 1% 1% Contingency utilisation (%) 36% 38% 63% 2% 2% 3% Required class of supply F F F E E E Actual class of supply F F F E E E The actual maximum demand 56.4 MVA is unreliable, so the load corrected maximum demand has been chosen as 47.4 MVA Casuarina zone substation 66/ /31.5/38 P (50) standard weather maximum demand (MVA) (the average actual maximum demand of 2008 and 2009/2010 actual maximum demands) Actual maximum demand (MVA) A load of MVA was transferred from the Berrimah zone substation on a permanent basis ) The actual maximum demand is very low in 2013/2014. May be due to the transfers to the Woolner zone substation. Maximum demands will be monitored. 2.) A new load of 1.07 MVA has been connected. 3.) A load of MVA has been transferred to the Berrimah zone substation on a permanent basis. 4.) A load of MVA has been transferred from the Berrimah zone substation on a permanent basis. Normal rating (MVA) Normal cyclic rating (MVA) A new load of 1 MVA will be connected ) A load of MVA will be transferred to the Leanyer zone substation on a permanent basis. Contingency cyclic rating (MVA) ) A load of 1.2 MVA will be disconnected from the Casuarina zone substation. 2nd contingency cyclic rating (MVA) The existing 3 x 25/31.5/38 MVA transformers will be replaced with 3 x 20/27 MVA transformers. Peak load temporary transfer (MVA) Normal cyclic ratings have been assumed to be the same as the normal ratings. Generation (MW) 28 N-2 criterion has been considered to calculate the second contingency cyclic rating for 'D' class of supply. Normal utilisation (%) 48% 42% 46% 46% 49% 39% 43% 28% 42% 42% 42% 29 Load can be transferred to the Berrimah zone substation. Contingency utilisation (%) 145% 63% 138% 139% 148% 59% 129% 43% 64% 64% 64% Required class of supply D C D D D C D C C C C Actual class of supply D* C D* D* D* C D* C C C C Class of supply 'D' maintained via transfer for second contingency. Centre Yard zone substation 66/ P (10) weather corrected maximum demand (MVA) The p (10) weather corrected maximum demands and actual maximum demands have been estimated. Actual maximum demand (MVA) Normal rating (MVA) Normal cyclic rating (MVA) Normal cyclic ratings have been assumed to be the same as the normal ratings. Contingency cyclic rating (MVA) Peak load temporary transfer (MVA) Generation (MW) Normal utilisation (%) 40% 40% 40% 40% 40% 40% 40% 40% 40% 40% 40% Contingency utilisation (%) 80% 80% 80% 80% 80% 80% 80% 80% 80% 80% 80% Required class of supply E E E E E E E E E E E Actual class of supply E E E E E E E E E E E

119 ZONE SUBSTATION / TRANSMISSION TERMINAL STATION / MODULAR SUBSTATION VOLTAGE (kv) INSTALLED CAPACITY HISTORICAL FORECAST NUMBER OF ITEM TRANSFORMER SIZES (MVA) / / / / / / / / / /2019 TRANSFORMERS Actual maximum demand (MVA) Normal rating (MVA) City zone substation 66/ /40 P (50) standard weather maximum demand (MVA) COMMENTS 32 A load of 5.87 MVA was transferred to the Frances Bay zone substation on a permanent basis. 33 A load of 2.53 MVA was transferred to the Frances Bay zone substation on a permanent basis. 34 A load of 2.58 MVA was transferred to the Frances Bay zone substation on a permanent basis ) A load of 16.9 MVA will be transferred to the Frances Bay zone substation on a permanent basis. 2.) A new load of 1 MVA will be connected. 3.) A new load of 1 MVA will be connected. 4.) A new load of 1.5 MVA will be connected. 5.) A new load of 1.8 MVA will be connected. 6.) A new load of 1.5 MVA will be connected. Normal cyclic rating (MVA) Contingency cyclic rating (MVA) The existing 3 x 30/40 MVA transformers will be replaced with 3 x 25/31.5/38 MVA transformers. 2nd contingency cyclic rating (MVA) Normal cyclic ratings have been assumed to be the same as the normal ratings. Peak load temporary transfer (MVA) N-2 criterion has been considered to calculate the second contingency cyclic rating for 'D' class of supply. Generation (MW) 39 Load can be transferred to the Frances Bay zone substation. Normal utilisation (%) 45% 45% 44% 43% 40% 41% 37% 43% 43% 44% 44% Contingency utilisation (%) 135% 135% 132% 128% 120% 122% 112% 128% 130% 132% 133% Required class of supply D D D D D D D D D D D Actual class of supply D* D* D* D* D* D* D* D* D* D* D* * Class of supply 'D' maintained via transfer for second contingency. Cosmo Howley zone substation 66/ P (10) weather corrected maximum demand (MVA) No further mine expansion is known. No expecting growth rate to continue. Actual maximum demand (MVA) Normal rating (MVA) Normal cyclic rating (MVA) Contingency cyclic rating (MVA) Peak load temporary transfer (MVA) Generation (MW) Normal utilisation (%) 3% 7% 7% 14% 24% 28% 35% 35% 35% 35% 35% Contingency utilisation (%) 5% 14% 15% 28% 48% 56% 69% 69% 69% 69% 69% Required class of supply E F F F F F G G G G G Actual class of supply E F F F F F G G G G G Frances Bay zone substation 66/ /38 P (50) standard weather maximum demand (MVA) A load of 5.87 MVA was transferred from the City zone substation on a permanent basis Actual maximum demand (MVA) A load of 2.53 MVA was transferred from the City zone substation on a permanent basis. 45 Normal rating (MVA) A load of 2.58 MVA was transferred from the City zone substation on a permanent basis. Normal cyclic rating (MVA) A load of 16.9 MVA will be transferred from the City zone substation on a permanent basis. Contingency cyclic rating (MVA) ` An additional 1 x 25/31.5/38 MVA transformer will be connected. 2nd contingency cyclic Rating (MVA) The normal cyclic rating of an additional transformer is assumed as 44.3 MVA. This assumption is based on the existing transformer normal cyclic rating 44.3 MVA. Peak load temporary transfer (MVA) N-2 criterion has been considered to calculate second contingency cyclic rating for 'D' class of supply. Generation (MW) 48 Load can be transferred to the City zone substation. Normal utilisation (%) 13% 19% 25% 25% 34% 34% 35% 36% 36% Contingency utilisation (%) N/A N/A N/A N/A N/A N/A N/A N/A N/A Required class of supply D D D D D D D D D Actual class of supply * D D D D D D D D D * Class of supply 'D' maintained via transfer for second contingency Hudson Creek transmission terminal station 132/ /125 P (50) standard weather maximum demand (MVA) The load growth is high due to the generation dispatch at the Weddell power station, so use the values with caution. Actual maximum demand (MVA) Normal rating (MVA) Normal cyclic rating (MVA) The normal cyclic ratings have been assumed to be the same as normal ratings. Contingency cyclic rating (MVA) Peak load temporary transfer (MVA) The generation output at the Weddell power station can be increased to supply the required load. Generation (MW) Normal utilisation (%) 50% 53% 49% 59% 55% 56% 64% 66% 68% 71% 73% Contingency utilisation (%) 75% 80% 74% 89% 82% 83% 96% 99% 103% 106% 109% Required class of supply D D D D D D D D D D D Actual class of supply D D D D D D D D D* D* D* * Class of supply 'D' maintained by increasing the generation output at the Weddell power station. Humpty Doo zone substation 66/ P (50) standard weather maximum demand (MVA) Feeder 22HD402 (Lambells) - temporary transfers only. Actual maximum demand (MVA) x 2.5 MVA transformer decommissioned in April Normal rating (MVA) Normal cyclic rating (MVA) Contingency cyclic rating (MVA) Peak load temporary transfer (MVA) Generation (MW) Normal utilisation (%) 15% 15% 39% 11% 14% 22% 28% 28% 28% 28% 28% Contingency utilisation (%) 23% 23% 79% 21% 28% 44% 56% 56% 56% 56% 56% Required class of supply F F F E F F F F F F F Actual class of supply F F F E F F F F F F F 54 A new load of 0.05 MVA has been added. Katherine zone substation 132/ x 20/27 1 x 20/33 P (50) standard weather maximum demand (MVA) x 20/27 MVA transformer has been replaced with a new 1 x 20/33 MVA transformer. Actual maximum demand (MVA) Normal rating (MVA) Normal cyclic rating (MVA) The normal cyclic rating of the new transformer is assumed to be the same as normal rating 33 MVA. Contingency cyclic rating (MVA) Peak load temporary transfer (MVA) Generation (MW) The installed capacity of generators at Katherine Power Station is 29.6 MW. The generator details are as follows: a) Katherine 1 (K 1) - 7 MW b) Katherine 2 (K 2) - 7 MW c) Katherine 4 (K 4) - 12 MW d) Cummings B (Mobile generator) MW e) Cummings C (Mobile generator) MW f) Cummings D (Mobile generator) MW g) Cummings E (Mobile generator) MW Normal utilisation (%) 54% 47% 46% 45% 43% 42% 44% 43% 41% 40% 39% Contingency utilisation (%) 108% 94% 93% 90% 91% 89% 93% 90% 88% 85% 82% Required class of supply C C C C C C C C C C C Actual class of supply C* C C C C C C C C C C Class of supply 'C' is maintained via non-network solution (Generation). * ) Leanyer ZSS will be commissioned in 2015/2016 with 2 x 20/27 MVA transformers. 2.) A load of MVA will be transferred from the Berrimah zone substation on a permanent basis. Leanyer zone substation 66/ /27 P (50) standard weather maximum demand (MVA) ) Load of MVA will be transferred from the Casuarina zone substation on a permanent basis. Actual maximum demand (MVA) Normal rating (MVA) Normal cyclic rating (MVA) Normal cyclic ratings have been assumed to be the same as normal ratings. Contingency cyclic rating (MVA) Peak load temporary transfer (MVA) Generation (MW) Normal utilisation (%) 39% 40% 41% 42% Contingency utilisation (%) 79% 80% 82% 84% Required class of supply C C C C Actual class of supply C C C C

120 ZONE SUBSTATION / TRANSMISSION TERMINAL STATION / MODULAR SUBSTATION VOLTAGE (kv) INSTALLED CAPACITY HISTORICAL FORECAST NUMBER OF ITEM TRANSFORMER SIZES (MVA) / / / / / / / / / /2019 TRANSFORMERS 62 Manton zone substation 132/ /27 P (50) standard weather maximum demand (MVA) COMMENTS 60 60A switching Transfer in 2011/2012 & 2012/2013 calculated as MVA. Construction works have affected peak readings with transfers etc. Load is not expected to continue to reduce beyond 5 years. Will be re-assessed in future once the system is returned to 'normal' following Manton zone substation commissioning Manton zone substation was out of service during the year 2013/2014. The following temporary transfers to Batchelor and McMinns zone substations have been assumed. 1.) 1.5 MVA load transfer to the Batchelor zone substation. 2.) 2.37 MVA load transfer to the McMinns zone substation. Actual maximum demand (MVA) Normal rating (MVA) A new load 4.7 MVA will be connected. Normal cyclic rating (MVA) Contingency cyclic rating (MVA) Peak load temporary transfer (MVA) Load can be transferred to the Batchelor zone substation. Generation (MW) Normal utilisation (%) 17% 17% 14% 6% 5% 0% 25% 24% 23% 22% 21% Contingency utilisation (%) N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A Required class of supply G G F F F E G G G G G * Actual class of supply * G G F F F E G G G G G Class of supply 'F' and 'G' are maintained via transfer Mary River zone substation 66/22 1 8/12 (Nomad) P (10) weather corrected maximum demand (MVA) The p (10) weather corrected maximum demands and actual maximum demands have been estimated A new load of 0.01 MVA has been connected. Actual maximum demand (MVA) Normal rating (MVA) Normal cyclic rating (MVA) Contingency cyclic rating (MVA) Peak load temporary transfer (MVA) Generation (MW) ` Normal utilisation (%) 24% 24% 25% 26% 17% 22% 28% 45% 46% 47% 48% Contingency utilisation (%) N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A Required class of supply F F F F F F F F F F F Actual class of supply E E E E E E E E E E E 69 Marrakai zone substation 66/ P (10) weather corrected maximum demand (MVA) 0.5 Actual maximum demand (MVA) Normal rating (MVA) A Nomad mobile substation (8/12 MVA) was installed at the Mary River zone substation in September 2012 to supply the load. 67 Normal cyclic ratings have been assumed to be the same as normal ratings. 68 Nomad (8/12 MVA) will be replaced with a new 1 x 5/7.5 MVA transformer ) The loads connected to the micro sub 0952 will be transferred to the Marrakai zone substation on a permanent basis. 2.) The Marrakai zone substation load has been estimated based on capacity of the micro-sub 0952 (500 KVA) along the 66 kv transmission line. 70 The Marrakai zone substation will be commissioned with 2 x 2.5 MVA transformers Normal cyclic rating (MVA) Normal cyclic ratings have been assumed to be the same as normal ratings. Contingency cyclic rating (MVA) Peak load temporary transfer (MVA) Generation (MW) Normal utilisation (%) 10% 10% 10% 10% 10% Contingency utilisation (%) 20% 20% 20% 20% 20% Required class of supply E E E E E Actual class of supply E E E E E ) Manton zone substation was out of service during the year 2013/ MVA temporary load transfer from the Manton zone substation has been assumed. 2.) A new load of 1.8 MVA has been connected. McMinns zone substation 66/ /13.5 P (50) standard weather maximum demand (MVA) ) A new load of 3.4 MVA will be connected. 2.) A new load of 1 MVA will be connected. Actual maximum demand (MVA) ) A new load of 4.9 MVA will be connected. 2.) A new load of 2.5 MVA will be connected. Normal rating (MVA) A load of 11.5 MVA will be disconnected from the McMinns zone substation. Normal cyclic rating (MVA) The existing 3 x 10/13.5 MVA transformers will be replaced with 2 x 20/27 MVA transformers. This is a part of replacing McMinns zone substation and the name of the new zone substation will be Strangways zone substation. Contingency cyclic rating (MVA) The normal cyclic ratings have been assumed to be the same as normal ratings. Peak load temporary transfer (MVA) Generation (MW) 78 Load can be transferred to the Palmerston (11/22 kv) zone substation. Normal utilisation (%) 34% 42% 40% 50% 42% 49% 56% 73% 66% 67% 47% Contingency utilisation (%) 52% 62% 60% 75% 63% 74% 85% 110% 132% 134% 94% Required class of supply H H H H H H H H H H H Actual class of supply H H H H H H H H* H* H* H * Class of supply 'H' maintained via transfer Palmerston zone substation 66/ /40 P (50) standard weather maximum demand (MVA) A load of MVA was transferred to the Archer zone substation on a permanent basis ) A new load of 1.95 MVA has been connected. 2.) MVA load has been connected. Actual maximum demand (MVA) ) A new load of MVA will be connected. 2.) A load of MVA will be transferred to the Archer zone substation on a permanent basis. Normal rating (MVA) ) A new load of 1 MVA will be connected ) A new load of 4 MVA will be connected. 2.) A new load of MVA will be connected. Normal cyclic rating (MVA) ) A new load of MVA will be connected ) A new load of 4 MVA will be connected. Contingency cyclic rating (MVA) ) A new load of 2 MVA will be connected. 84 A new load of 2 MVA will be connected. 2nd contingency Cyclic Rating (MVA) A new 1 x 30/40 MVA transformer will be connected. Peak load temporary transfer (MVA) ) The normal rating and normal cyclic rating of existing Palmerston zone substation transformers are limited to 38.1 MVA due to the 11kV circuit breaker rating of 2000A 2.) The normal cyclic rating of the new transformer 1 x 30/40 MVA has been assumed to be the same as normal rating. The new Generation (MW) transformer will be connected in 2016/ N-2 criterion has been considered to calculate the second contingency cyclic rating for 'D' class of supply. Normal utilisation (MVA) 56% 56% 60% 58% 41% 41% 45% 58% 44% 44% 47% 88 Load can be transferred to the Berrimah zone substation and subsequently to the Casuarina zone substation. Contingency utilisation (MVA) 111% 113% 120% 116% 82% 83% 89% 116% 134% 136% 143% Required class of supply (MVA) C C C C C C C C D D D Actual class of supply (MVA) C* C* C* C* C C C C* D* D* D* * Class of supply 'C' and 'D' are maintained via transfer The p (50) standard weather maximum demands have been assumed to be the same as actual maximum demands. Palmerston zone substation 11/ P (50) standard weather maximum demand (MVA) A new load of 1.95 MVA has been connected. Actual maximum demand (MVA) Normal rating (MVA) An additional transfomer 1 x 15/19 MVA will be connected. Normal cyclic rating (MVA) Normal cyclic ratings have been assumed to be the same as normal ratings. Contingency cyclic rating (MVA) Peak load temporary transfer (MVA) Load can be transferred to the McMinns zone substation. Generation (MW) Normal utilisation (MVA) 36% 35% 41% 37% 33% 60% 64% 19% 20% 21% 22% Contingency utilisation (MVA) N/A N/A N/A N/A N/A N/A N/A 67% 71% 73% 76% Required class of supply (MVA) F F F F F F F G G G G Actual class of supply (MVA) F* F* F* F* F* F* F* G G G G * Class of supply 'F' maintained via transfer ) The p (50) standard weather maximum demands and actual maximum demands have been estimated based on the maximum demand of PC-UR-BC-CH line. 2.) 17.1 MVA load has been estimated from the year 2013/2014 to 2018/2019 based on the following loads connected to PC-UR- BC-CH line. Cosmo Howley zone substation MVA Union Reef zone substation MVA Pine Creek transmission terminal station 132/66 1 (18/18/10) / (30/30/10) P (50) standard weather maximum demand (MVA) Other loads - 1 MVA Actual maximum demand (MVA) x 18/30 MVA transformer replaced with 1 x 35 MVA transformer. Normal rating (MVA) Normal cyclic ratings have been assumed to be the same as normal ratings. Normal cyclic rating (MVA) Contingency cyclic rating (MVA) Peak load temporary transfer (MVA) Load can be transferred to the Pine Creek (66/11kV) zone substation. Generation (MW) Normal utilisation (MVA) 37% 37% 43% 43% 43% 57% 57% 57% 57% 57% 57% Contingency utilisation (MVA) N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A Required class of supply (MVA) G G G G G H H H H H H Actual class of supply (MVA) * G G G G G H H H H H H * Class of supply 'G' and 'H" are maintained via transfer.

121 ZONE SUBSTATION / TRANSMISSION TERMINAL STATION / MODULAR SUBSTATION VOLTAGE (kv) INSTALLED CAPACITY HISTORICAL FORECAST NUMBER OF ITEM TRANSFORMER SIZES (MVA) / / / / / / / / / /2019 TRANSFORMERS Pine Creek zone substation 66/ P (50) standard weather maximum demand (MVA) ) The p (50) standard weather maximum demands and actual maximum demands have been estimated based on the maximum demand of PC-UR-BC-CH line. 2.) 17.1 MVA load has been estimated from the year 2013/2014 to 2018/2019 based on the following loads connected to PC-UR- BC-CH line. Cosmo Howley zone substation MVA Union Reef zone substation MVA Other loads - 1 MVA Actual maximum demand (MVA) Normal rating (MVA) Normal cyclic rating (MVA) Normal cyclic ratings have been assumed to be the same as normal ratings. Contingency cyclic rating (MVA) Peak load temporary transfer (MVA) Generation (MW) The installed capacity of generators at Pine Creek power station is 25 MW. The generator details are as follows: a.) Pine Creek 1 (P 1) - 9 MW b.) Pine Creek 2 (P 2) - 9 MW c.) Pine Creek 3 (P 3) - 7 MW Normal utilisation (MVA) 32% 32% 32% 32% 32% 43% 43% 43% 43% 43% 43% Contingency utilisation (MVA) 65% 65% 65% 65% 65% 86% 86% 86% 86% 86% 86% Required class of supply (MVA) G G G G G H H H H H H Actual class of supply (MVA) G G G G G H H H H H H Pine Creek zone substation 11/ P (50) standard weather maximum demand (MVA) Pine Creek load was transferred to the Katherine zone substation. Actual maximum demand (MVA) x 1.8 MVA transformer replaced the previous 4 x 2.5 MVA transformers. Normal rating (MVA) Normal cyclic rating (MVA) Normal cyclic ratings have been assumed to be the same as normal ratings. Contingency cyclic rating (MVA) Peak load temporary transfer (MVA) Load can be transferred to the Katherine zone substation. Generation (MW) Normal utilisation (MVA) 0% 0% 0% 0% 0% 72% 78% 78% 83% 83% 83% Contingency utilisation (MVA) N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A Required class of supply (MVA) E E E E E F F F F F F * Class of supply 'F' maintained via transfer. Actual Class of Supply (MVA) E E E E E F* F* F* F* F* F* Load was transferred to the Woolner zone substation permanently as the Snell Street zone substation is replaced with the 3 x 10/12 Snell Street zone substation 66/ x 11 P (50) standard weather maximum demand (MVA) Woolner zone substation. Actual maximum demand (MVA) Normal rating (MVA) Normal cyclic rating (MVA) Contingency cyclic rating (MVA) Peak load temporary transfer (MVA) Generation (MW) Normal utilisation (%) 56% 55% 64% 63% 65% Contingency utilisation (%) 75% 73% 86% 84% 87% Required class of supply C C C C C Actual class of supply C C C C C Tindal zone substation 22/ P (50) standard weather maximum demand (MVA) Actual maximum demand (MVA) Normal rating (MVA) Normal cyclic rating (MVA) Contingency cyclic rating (MVA) Peak load temporary transfer (MVA) Generation (MW) Normal utilisation (%) 35% 37% 38% 38% 33% 34% 36% 36% 35% 34% 34% Contingency utilisation (%) 52% 55% 57% 56% 50% 51% 55% 53% 52% 51% 51% Required class of supply F F F F F F F F F F F Actual class of supply F F F F F F F F F F F A new load of 0.38 MVA has been connected. Weddell zone substation 66/22 2 5/7.5 P (50) standard weather maximum demand (MVA) A new load of 3 MVA will be connected. Actual maximum demand (MVA) A load of 10 MVA will be disconnected from the Weddell zone substation. Normal rating (MVA) Normal cyclic rating (MVA) x 10/13.5 MVA transformer will be installed to provide capacity for the Inpex load. Contingency cyclic rating (MVA) Normal cyclic ratings have been assumed to be the same as normal ratings. 111 Normal cyclic rating of the new transformer (10/13.5 MVA) has been assumed to be the same as normal rating. Peak load temporary transfer (MVA) Generation (MW) Normal utilisation (%) 24% 31% 46% 42% 38% 41% 45% 14% 18% Contingency utilisation (%) 48% 62% 92% 85% 71% 77% 84% 26% 33% Required class of supply F F G G G G G F G Actual class of supply F F G G G G G F G Wishart modular substation 66/11 1 8/12 (Nomad) P (50) standard weather maximum demand (MVA) MVA load will be transferred from the Berrimah zone substation on a permanent basis. Actual maximum demand (MVA) 113 This is an interim solution with 1 x 8/12 Nomad, which is required to meet expected demand and maintain load security. A full capacity zone substation will be required in the future. Normal rating (MVA) Normal cyclic rating (MVA) Normal cyclic ratings have been assumed to be the same as the normal ratings. 114 Contingency cyclic rating (MVA) Peak load temporary transfer (MVA) Load can be transferred to the Berrimah zone substation. Generation (MW) Normal utilisation (%) 75% 77% 78% 80% 82% Contingency utilisation (%) N/A N/A N/A N/A N/A Required class of supply C C C C C * Class of supply 'C' maintained via transfer. Actual Class of Supply (MVA) * C C C C C Woolner zone substation 66/ /27 P (50) standard weather maximum demand (MVA) The load has increased due to the commisioning of Woolner zone substation has been assumed. Actual maximum demand (MVA) Normal rating (MVA) Normal cyclic rating (MVA) Contingency cyclic rating (MVA) Peak load temporary transfer (MVA) Generation (MW) Normal utilisation (%) 46% 54% 57% 59% 62% 65% Contingency utilisation (%) 68% 81% 85% 89% 93% 98% Required class of supply C C C D D D Actual class of supply C C C D D D COMMENTS

122 ZONE SUBSTATION / TRANSMISSION TERMINAL STATION / MODULAR SUBSTATION VOLTAGE (kv) INSTALLED CAPACITY HISTORICAL FORECAST NUMBER OF ITEM TRANSFORMER SIZES (MVA) / / / / / / / / / /2019 TRANSFORMERS COMMENTS Alice Springs 118 Lovegrove zone substation 22/ x 7.5/10 1 x12/15 P (50) standard weather maximum demand (MVA) Actual maximum demand (MVA) Normal rating (MVA) Normal cyclic rating (MVA) Contingency cyclic rating (MVA) Peak load temporary transfer (MVA) Generation (MW) Normal utilisation (%) 27% 21% 28% 29% 31% 36% 51% 52% 53% 54% 55% Contingency utilisation (%) 47% 37% 49% 50% 54% 64% 90% 91% 93% 95% 96% Required class of supply C C C C C C C C C C C Actual class of supply C C C C C C C C C C C Lovegrove zone substation (22 kv load) P (10) weather corrected maximum demand (MVA) Actual maximum demand (MVA) Normal rating (MVA) Normal cyclic rating (MVA) Contingency cyclic rating (MVA) Peak load temporary transfer (MVA) Generation (MW) Normal utilisation (%) Contingency utilisation (%) Required class of supply Actual class of supply Lovegrove zone substation 66/ /45 P (50) standard weather maximum demand (MVA) MVA load has been transferred temporarily to the Sadadeen zone substation (Ron Goodin 11 kv load). 118 A load of 4.36 MVA will be transferred from the Sadadeen zone substation (Ron Goodin 11 kv load) on a permanent basis. 119 The p (50) standard weather maximum demands and actual maximum demands are estimated based on the rating of express feeders (20 MVA) and local load (Lovegrove zone substation 22/11 kv + Lovegrove zone substation 22 kv load). Actual maximum demand (MVA) Normal rating (MVA) Normal cyclic rating (MVA) Normal cyclic ratings have been assumed to be the same as normal ratings. Contingency cyclic rating (MVA) Peak load temporary transfer (MVA) Generation (MW) Normal utilisation (%) 38% 39% 29% 34% 35% 35% 35% 36% Contingency utilisation (%) 76% 79% 58% 69% 69% 70% 71% 71% Required class of supply C C C C C C C C Actual class of supply C C C C C C C C 121 The p (50) standard weather maximum demands and actual maximum demands are estimated based on the rating of express Owen Springs transmission teminal station 11/ /45 P (50) standard weather maximum demand (MVA) feeders (20 MVA) and local load (Lovegrove zone substation 22/11 kv + Lovegrove zone substation 22 kv load). Actual maximum demand (MVA) Normal rating (MVA) Normal cyclic rating (MVA) Normal cyclic ratings have been assumed to be the same as normal ratings Contingency cyclic rating (MVA) Peak load temporary transfer (MVA) Generation (MW) The installed capacity of generators at the Owen Springs Power Station is 35.5 MW. The generators details are as follows: a) Owen Springs generator 1 (OS 1) MW b) Owen Springs generator 2 (OS 2) MW c) Owen Springs generator 3 (OS 3) MW d) Taurus (Mobile generator) - 4 MW Normal utilisation (%) 38% 39% 28% 33% 33% 34% 34% 34% Contingency utilisation (%) 76% 79% 56% 66% 66% 67% 68% 68% Required class of supply C C C C C C C C Actual class of supply C C C C C C C C MVA has been transferred temporarily from the Lovegrove (22/11 kv) zone substation. Sadadeen zone substation (Ron Goodin 11 kv load) 22/ /19 P (50) standard weather maximum demand (MVA) Actual maximum demand (MVA) A load of 4.36 MVA will be transferred to the Lovegrove (22/11 kv) zone substation on a permanent basis. Normal rating (MVA) Normal cyclic rating (MVA) Contingency cyclic rating (MVA) Peak load temporary transfer (MVA) Generation (MW) Normal utilisation (%) 71% 70% 68% 64% 59% 72% 69% 64% 60% 55% 51% Contingency utilisation (%) 142% 139% 137% 127% 118% 143% 137% 128% 119% 111% 102% Required class of supply C C C C C C C C C C C Actual class of supply * C C C C C C C* C* C* C* C* 128 Brewer + Sadadeen 22kV (Balance loads) P (50) standard weather maximum demand (MVA) Tennant Creek (coupling transformers in between Ron Goodin and Sadadeen) 126 The installed capacity of generators at the Ron Goodin power station is 32.1 MW. The generators details are as follows: a) Ron Goodin generator 1 (RG 1) MW b) Ron Goodin generator 2 (RG 2) MW c) Ron Goodin generator 3 (RG 3) MW d) Ron Goodin generator 4 (RG 4) MW e) Ron Goodin generator 5 (RG 5) MW f) Ron Goodin generator 6 (RG 6) MW g) Ron Goodin generator 7 (RG 7) MW h) Ron Goodin generator 8 (RG 8) MW * Utilisation of C is maintained via non-network solution (Generation) Actual maximum demand (MVA) A new load of 1.5 MVA will be connected. Normal rating (MVA) Normal cyclic rating (MVA) Contingency cyclic rating (MVA) Peak load temporary transfer (MVA) Generation (MW) Normal utilisation (%) Contingency utilisation (%) Required class of supply Actual class of supply ) The p (50) standard weather maximum demands and actual maximum demands have been estimated. 2.) These loads are the balance of load at sites without transformers. Tennant Creek zone substation 11/ P (50) standard weather maximum demand (MVA) A new load of MVA will be connected. Actual maximum demand (MVA) Normal rating (MVA) Normal cyclic rating (MVA) Contingency cyclic rating (MVA) Peak load temporary transfer (MVA) Generation (MW) Normal utilisation (%) 32% 41% 41% 40% 41% 45% 46% 53% 52% 51% 51% Contingency utilisation (%) 65% 81% 81% 80% 82% 90% 92% 106% 105% 102% 102% Required class of supply G G G G G G G G G G G * * * * * The security risk is acceptable based on the following information. Actual class of supply G G G G G G G F F F F - The period of peak load is very short, within supply restoration requirements. - The overall maximum demand is declined from 2016/2017 onwards.

123 APPENDIX 4 REGIONAL LOAD PROFILES

124 Darwin-Katherine System Daily Maximum Demand (2013/2014) July Aug Sep Oct Nov Dec Jan Feb March April May June Wet Season Daily Maximum Demand (MW) Days Per Year

125 320 Darwin-Katherine System Hourly Demand Curves (2013/2014) Dry Season Hourly Demand (MW) Maximum Daily Demand Minimum Daily Demand Average Daily Demand Hours Per Day

126 320 Darwin-Katherine System Hourly Demand Curves (2013/2014) Wet Season Hourly Demand (MW) Maximum Daily Demand Minimum Daily Demand Average Daily Demand Hours Per Day Systemblack occured on 12th March

127 60 Alice Springs System Daily Maximum Demand (2013/2014) July Aug Sep Oct Nov Dec Jan Feb March April May June Summer Season 50 Daily Maximum Demand (MW) Days Per Year

128 60 Alice Springs System Hourly Demand Curves (2013/2014) Summer Season Hourly Demand (MW) Maximum Daily Demand Minimum Daily Demand Average Daily Demand Hours Per Day

129 50 Alice Springs System Hourly Demand Curves (2013/2014) Winter Season Hourly Demand (MW) Maximum Daily Demand Minimum Daily Demand Average Daily Demand Hours Per Day

130 8 Tennant Creek System Daily Maximum Demand (2013/2014) July Aug Sep Oct Nov Dec Jan March April May June Feb 7 Daily Maximum Demand (MW) Days Per Year

131 APPENDIX 5 MINOR CAPITAL ASSET REPLACEMENT PROGRAMS Planned Asset Replacement Quantities for 2014/15 and 5 year forecast. Program 2014/15 Qty 5 Year Planned Qty Asset Replacement and Upgrade Programs Low Voltage Pillars BBC Switchboards 9 15 Cast Iron Potheads 9 33 Aerial Bundled Conductor 0km 10km Fault Rating Replacement of Switchgear 7 12 Service Dead-ends Pole Rehabilitation Substation Dehumidifiers kV GIS Corrosion Protection Upgrade 1 1 Neutral Earthing Resistors 0 5 ZSS CB Replacements (excl. Hudson Ck 132kV) 5 8 HV Cable Replacement Program 2.4km 9km ORMU Replacement Program Feeder Upgrade Program Reclosers 12 Overhead switching point automation 65 Pole Hardware Upgrades 1055 TBD* TBD* TBD* Protection Upgrade Program 5 42 Underground Distribution Substation Replacement Program *Planned developed annually for specific feeders that breach performance criteria.

132 NETWORKMANAGEMENTPLAN 2013/14to2018/19