AsetManagementPlan.

Transcription

1 2012 AsetManagementPlan

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3 Introduction It gives me great pleasure to present Top Energy s Network Asset Management Plan (AMP). The 2012 plan follows on from the 2011 plan, addressing the key issues of reliability, security of supply and capacity. In this plan, we detail our reliability improvement programme as well as a significant transmission and sub-transmission investment plan over the next decade. This AMP is the core asset management planning and operations document for Top Energy and details inspection, maintenance and capital replacement strategies, as well as the service level targets that we intend to deliver to our customers. In compiling this plan, emphasis has been given to ensuring compliance with the Commerce Commission s Disclosure Requirements, whilst also providing detailed information about Top Energy s asset management and planning processes. The Commerce Commission requires that electricity distribution businesses (EDBs) publicly disclose an AMP each year that provides information on how the business intends to manage its network assets to meet the requirements of its consumers. In 2011, Top Energy s AMP was assessed as being the most compliant with disclosure requirements among the 28 EDBs, an achievement that we are very proud of. Figure 1: 2011 Asset Management Plan Review Rankings In 2009, we introduced a major reliability programme which has targeted the clearance of trees near lines, the installation of automated switches and re-closers in strategic locations, and the use of specialised equipment to reduce the impacts of lightning strikes. This programme resulted in a significant improvement in the performance of the network in the last two years. As of writing, customers in the Far North have experienced 354 SAIDI minutes without power (on average) since the beginning of April 2011, a 61% improvement on the FYE2009 figure of 924 SAIDI minutes and a 19% improvement on the performance for the same period last year. It is planned that reliability improvement will continue and deliver a target of 200 SAIDI minutes by the year The 2010 Top Energy AMP announced a 10 year sub-transmission development plan aimed at improving quality of supply by providing more points of injection into the distribution network. Building upon those plans, the 2011 AMP announced Top Energy s plan to supplement the sub-transmission development plan with a transmission development plan, designed to address the 110kV security of supply issues to the Kaitaia region. I am pleased to report that we have signed contracts with Transpower to take ownership of the majority of their transmission assets in the Far North from 1 st April This AMP details our plans for managing these newly acquired assets over the next decade

4 The investment in the region s 110kV assets is critical to our network expansion and reliability plans between now and It includes ownership of both the substations in Kaikohe and Kaitaia and 90km of connecting 110kV line between them, it is Top Energy s largest network asset acquisition yet. We believe that having the entire local lines network operated by just one company will result in savings and efficiencies worth $10 million, helping to keep power bills down in the long-term. In addition, the move increases security of supply and long-term electricity capacity for the whole of the Far North. The purchase of Transpower s Far North assets puts all maintenance and investment decisions into the hands of people who live and work in our own community. It s a really positive move for the Far North. Top Energy also has a number of other projects underway to help improve the reliability and security of the local electricity supply. These include: modernising infrastructure to improve reliability, doubling the size and capacity of the existing 33kV network by 2020, including new lines to Kerikeri and Waipapa building a back-up 110kV line to Kaitaia to enhance security of supply to East Coast communities (including Kerikeri and Taipa), substation construction right across the region to reduce the number and duration of outages, back-up infrastructure to reduce the number of outages even further, including short-term back-up diesel generation in Taipa, and trialling a new solar power project. A more stable and widespread electricity supply has financial benefits for the region. It makes the Far North a more attractive place to do business and more attractive to new investment, creating opportunities for employment and economic prosperity, we believe that s good for everyone. In addition to the technical development of the network assets, we also continue to develop the safety and asset management culture within Top Energy. In 2010, we received the Electricity Engineer s Association (EEA) Public Safety Award for our Close Approach Consent Process, which provides on-site safety advice and guidance for contractors and members of the public, when working within 4 metres of our lines. We followed this up in 2011, beating six other companies to win the industry s top award for workplace safety. The EEA Workplace Safety Award recognised our safety-focused culture and significant reduction of lost time injuries (LTIs) from a historical high of 16 LTIs in 2004 to just one in the last twelve months. Our move to a safety-focused culture has transformed Top Energy from one of the worst performing lines companies in the industry to one of the best. To improve our asset management processes, we have chosen to develop a framework approach that aligns to the UK Publically Available Specification for Asset Management (PAS55), which was adopted by the UK electricity supply industry in We have been steadily improving our processes over the past three years, including our alignment with the PAS55 asset management standard. We have now embarked on formal certification to demonstrate continual improvement and comparability against international best practice, as part of our annual disclosures. Certification to PAS55 will provide assurance to our stakeholders that the asset management processes within Top Energy meet international best-practice and are continuously monitored and improved. We hope that you find this Asset Management Plan both comprehensive and informative. We welcome your feedback on the plan or any other aspect of Top Energy s business and performance. Feedback can be placed through the Top Energy website at or ed to info@topenergy.co.nz. Russell Shaw Chief Executive, Top Energy Ltd - 2 -

5 Table of Contents I n t r o d u c t io n 1 T a b l e o f Co n t e n t s 3 1. E x e c u t i v e S u m m a r y Company Background Asset Management Strategy Network Description Value of Network Areas of Uneconomic Supply Reliability Network Development Plan B a c k g r o u n d a n d Ob j e c t i v e s Overview Purpose of this Plan Rationale for Asset Ownership Strategic Environment for Asset Management Planning Asset Management Planning and Implementation Asset Management Systems Business Processes and Information Flow Requirements A s s e t D e s c r ip t io n Overview Asset Details by Category Justification for Assets L e v e l o f S e r v ic e Introduction Customer Orientated Service Levels Asset Performance and Efficiency Targets Justification for Service Level Targets N e t wo r k D e v e lo p m e n t P la n n in g Planned Expenditure Planning Criteria Distribution Policy on Acquisition of New Assets Project Prioritisation Methodology Demand Forecast Network Development Plan Project Time line and Costs Detailed Project Descriptions and Development Timeline

6 5.10 Breakdown of the Capital Expenditure Budget L i f e c y c le A s s e t M a n a g e m e n t Maintenance and Renewal Planning Criteria and Assumptions Transmission Assets Overhead Conductors Poles and Structures Underground & Submarine Cables Distribution and SWER Transformers Auto-Reclosers Regulators Ring Main Units (RMU) Sectionalisers Capacitors Zone Substation Transformers Circuit Breakers Zone Substation Structures Zone Substation DC Systems Zone Substation Protection Zone Substation Grounds and Buildings Customer Service Pillars Earth installations SCADA and Communications Load Control Plant Total Maintenance and Renewal Expenditure Forecast R is k M a n a g e m e n t Risk Management Policy Risk Mitigation E v a lu a t io n o f P e r fo r m a n c e Introduction Review of Performance against Targets Asset Management Improvement Programme A c t u a l, B u d g e t a n d Fo r e c a s t E xp e n d it u r e year forecast of capital and operational expenditure Reconciliation of actual expenditure against expenditure for FYE Significant assumptions A p p e n d ic e s Appendix A Nomenclature Appendix B 2009 Customer Consultation Survey Questions Appendix C Risk Management Framework Appendix D - Emergency Response Plan Table of Contents

7 10.5 Appendix E Cross References to Requirements of Electricity Information Disclosure Handbook 2004 (as amended 31 October 2008) List of Figures

8 EXECUTIVE SUMMARY Section 1 Executive Summary I n t r o d u c t io n 1 T a b l e o f Co n t e n t s 3 1. E x e c u t i v e S u m m a r y Company Background Asset Management Strategy Network Description Value of Network Areas of Uneconomic Supply Reliability Network Development Plan

9 EXECUTIVE SUMMARY 1. Executive Summary 1.1 Company Background Top Energy Limited is part of the Top Energy group of companies and is wholly New Zealand owned and operated. The group includes: Top Energy Ltd, Top Electrical Ltd, Ngawha Generation Ltd, Ngawha Geothermal Resource Ltd, Ngawha Properties Ltd and PhonePlus 2000 Ltd. Top Energy Limited is the local electricity distribution lines business that supplies approximately 31,000 electricity consumers in the Mid and Far North of the Northland region, New Zealand. It employs around 200 people and is one of the largest employers in the Far North. Top Energy was first established in 1935 as the Bay of Islands Electric Power Board. The company is registered under the Companies Act 1993, owned by Top Energy Consumer Trust and governed by an independent Board of Directors. 1.2 Asset Management Strategy During the period 2012 to 2022, Top Energy is planning to make a significant investment in its aging and historically unreliable electricity network assets, including the transmission assets that it will acquire from Transpower on 1 April The key drivers are to improve: operational performance, security of supply, and service provision to electricity consumers on the Top Energy electricity network. Network Reliability In spite of recent improvements in performance, Top Energy remains the worst performing electricity distribution company in New Zealand for network reliability. During the year ending (YE) 2011, on average, each customer experienced five outages and more than seven hours without electricity. Whilst this performance was once viewed as the result of a complex mix of historical design, investment, ecological and climatic factors, it is now recognised that with suitable strategies and funding, the effects of these factors can be mitigated. Therefore, this AMP identifies the strategies that will be applied to mitigate the factors as far as is economically practicable. Demographic Challenges The challenges that Top Energy currently face in improving security of supply and network performance can, to some degree, be explained by the fringe location of its network and the location of the 110 kv infrastructure relative to the major population centres. This latter problem harks back to an era when the inland urban centres of Kaikohe and Kaitaia were the hubs of both economic and population growth within the Far North region. Over the last twenty years, there has been a steady decline in the growth of Kaikohe and significant expansion in the areas of Kerikeri, the Bay of Islands and the eastern coastal peninsulas. Parts of the network that previously supplied fringe coastal communities are now operating at over 90% capacity during peak periods. This demographic change limits the ability of the existing network to accommodate the connection of new customers in many areas and makes it more difficult to restore supply when a fault occurs. Network Expansion To address these issues and improve security of supply, Top Energy will invest around $150 million during the next decade, in what will be the single largest expansion in the history of the Top Energy electricity network. Within the next five years, Top Energy will construct a new 110 kv transmission line over a coastal route between Kaikohe and Kaitaia to improve the security of supply to the northern region, through the installation of a second high capacity incoming circuit to Kaitaia and enable the construction of a new 110kV transmission 7

10 EXECUTIVE SUMMARY substation at Wiroa to serve customers in Kerikeri and the coastal regions in the north east of Top Energy s supply area. The expansion will also strengthen the 33kV sub-transmission system, enabling an increase of the number of points at which power is injected into the older distribution network. It will also significantly increase the longterm security and reliability of the network to support future economic growth. Key sub-transmission projects planned include four new transmission and sub-transmission substations and substantial 110kVand 33kV line construction, which will replace short-term measures currently in place. For example, in FYE 2012 Top Energy installed diesel generation at Taipa to provide a backup power supply to cover the loss of the incoming 33kV supply. Vegetation control and strengthening the distribution s network s ability to withstand adverse weather events is also a focus for strategic investment and presents additional opportunities for significant performance improvement. In April 2009, we began a major reliability programme addressing the clearance of trees and vegetation near our lines. We also installed specialist equipment to reduce the number of faults that were caused by lightning and installed over 200 automated switches and re-closers in strategic locations. This limited the number of customers affected by each fault event and, in many cases, the time required to restore supply. Overall, the results have been excellent and we more than halved the total time that the average consumer went without electricity. (Over 900 SAIDI minutes in YE 2009 to 440 SAIDI minutes in YE 2011). Further, the number of outages experienced by our consumers was also more than halved during the same period. We will continue to invest in new technologies and strategies that offer the best mix of performance gains compared to the cost of implementation. 1.3 Network Description Top Energy s electricity network begins in Hukerenui, approximately 15km north of Whangarei and ends at Te Paki, 20 km south of Cape Reinga. It spans from the east coast to the west coast. Figure 2: Top Energy Sub-transmission lines (33kV) and transmission Transpower (110kV) 8

11 EXECUTIVE SUMMARY DESCRIPTION QUANTITY Area Covered 6,822km 2 Customer Connection Points 31,002 Grid Exit Points 2 : Kaikohe & Kaitaia 1 Embedded Generator Injection Points 1 : Ngawha Geothermal Network Peak Demand (to 31/12/2011) 70.7MW Electricity Delivered to Customers (YE 2011) 327GWh Number of Distribution Feeders 47 Distribution Transformer Capacity 251MVA Sub transmission Cables (33kV) 0.5km Sub transmission Lines (33kV) 263km HV Distribution Cables (22,11,6.35kV) 165km HV Distribution Lines (22,11,6.35kV including single wire earth return) 2,738km Note 1: As of 1 April 2012, Kaikohe will be the only point where Top Energy takes supply from the Transpower Grid. Figure 3: Network Summary (as at 31 March 2011 unless otherwise shown) 1.4 Value of Network In accordance with the Commerce Commission s Electricity Distribution Information Disclosure Requirements 2008, Top Energy discloses that its system fixed assets are valued at $143,974,000 as at 31 March 2011, an increase of $11,721,000 since 31 March This total does not include transmission assets that Top Energy will acquire from Transpower on 1 April 2012, valued at around $7 million. This increase in asset value is derived as follows: $000 Asset Value at 31 March ,253 Add: Addition of new assets 11,362 Indexed inflation adjustment 5,907 Less Depreciation 5,548 Asset value at 31 March ,974 Figure 4: Value of System Fixed Assets 9

12 1.5 Areas of Uneconomic Supply EXECUTIVE SUMMARY Over 35% of Top Energy s lines were originally built using subsidies provided by the Rural Electrical Reticulation Council (RERC). This provided assistance with post-war farming productivity growth in remote areas and supplying electricity to consumers located in sparsely populated rural areas, which would otherwise have been uneconomic to service. Many of these lines now require extensive rebuilding and refurbishment, to the extent that continuing to supply many of the sparsely populated rural areas is uneconomic. However, Top Energy is obligated by Section 105(2) of the Electricity Industry Act 2010 to continue to provide a supply to consumers supplied from existing lines. The Electricity Networks Association (ENA) created a working party to review the implications of this obligation, particularly for distribution companies that include a large rural network component. To assist this review, in April 2009 Top Energy engaged Intergraph to create a trace within its GIS system to identify uneconomic lines based on the Ministry of Economic Development (MED) suggested test scenarios. This trace stepped through each piece of equipment within the GIS, feeder by feeder and identified where uneconomic lines began. The start points were individually recorded and each of these start points became the beginning point of a further trace. This in turn identified all downstream equipment, therefore summing the length of uneconomic conductors. The results revealed that 32% of Top Energy lines were uneconomic, based on MED criteria. However, these lines feed only 8% of Top Energy s consumer base. The high proportion of uneconomic lines in Top Energy s supply area is a continuing financial burden on all Top Energy consumers. Figure 5: Map of uneconomic lines 10

13 EXECUTIVE SUMMARY 1.6 Reliability In FYE 2010, Top Energy s SAIDI was 440 minutes (System Average Interruption Duration Index, measuring the total number of minutes in a year that the average consumer is without electricity). This was a marked improvement in comparison to the previous year (2009), which resulted in 932 SAIDI minutes. The overall network quality performance for FYE 2011 resulted in a total of: kV and 33kV unplanned faults, and Top Energy planned outages. These faults and unplanned outages resulted in 440 SAIDI minutes, and 4.9 customer interruptions (SAIFI). SAIFI measures the number of interruptions experienced each year by the average consumer. The figure below shows that the most significant causes of unplanned interruptions were adverse weather, tree contacts, foreign interference and defective equipment: TOP ENERGY CAUSE OF UNPLANNED INTERRUPTION SAIDI % OF TOTAL SAIDI Adverse Environment Adverse Weather Defective Equipment Foreign Interference Human Element Lightning Tree Contacts Unknown Total Figure 6: Causes of interruptions Equipment failure had the greatest impact on network performance in FYE The levels of service experienced by any individual consumer are the result of many factors, including the network security of supply standards adopted, the remoteness of that consumer, resource locations, network configuration, as well as maintenance, equipment failure mechanisms, and the weather. Top Energy must meet regulatory performance thresholds for SAIDI and SAIFI, covering both planned interruptions (Class B) and unplanned interruptions (Class C) that result on its network. The following figures show Top Energy s historical performance for both of these measures. The increase in the Commerce Commission s regulatory threshold values for FYE 2010 is reflective of the recalculation at the commencement of a new five year price/quality regulatory regime on 1st April Top Energy is subject to regulatory control by the Commerce Commission in accordance with Part IV of the Commerce Act

14 EXECUTIVE SUMMARY Figure 7: YTD Historical and YE2011 SAIDI performance SAIDI Threshold AMP Target SAIFI Threshold AMP Target YTD Figure 8: Historical and Current SAIFI performance To successfully achieve the performance improvements shown in Figures 7 and 8 above, Top Energy has made significant investment in the areas of: vegetation control lightning protection, network automation, live line working, modern protection systems, and condition-based maintenance strategies. 12

15 EXECUTIVE SUMMARY The success of these strategies is reflected in the greatly improved reliability achieved in FYE 2010 and FYE Top Energy anticipates further improvements in reliability, as the strategies detailed in this plan are progressively implemented. Reliability targets are based on normalised measures that partially exclude the impact of major event days, which arise when a severe storm passes though the Top Energy area. This is consistent with decisions taken by the Commerce Commission in setting the quality thresholds that will apply to the regulatory period. Top Energy believes the normalised measure better reflects its underlying management performance and is therefore a more reliable and useful management tool. Performance targets for are shown in Figure 9 below. The operational performance targets include the impact of both faults and planned outages in Top Energy s network and include an additional SAIDI component over previously published targets as a result of the transmission assets acquired from Transpower on 1 st April OPERATIONAL PERFORMANCE TARGET SAIDI (minutes) 402 SAIFI (no of interruptions) 5 FINANCIAL TARGET Operational Expenditure Ratio 4.75% TECHNICAL TARGET Loss Ratio 8% Figure 9: Service Level Targets 2012 to Network Development Plan Over the next ten years some 17 major capital projects have been identified in the Network Development Plan. These projects will transition the network from its current configuration to the proposed configuration shown in Figure 11 and, deliver the security and capacity improvements required. Project staging has been determined by a number of factors. Most critical were the anticipated timing of the security and capacity constraints on the network, ensuring that the network enhancements will be in place just before the constraints begin to have a negative impact on system performance and customer service. In addition, resource availability (human and financial) was considered and projects moved appropriately. The result is a work plan which will produce the desired performance outcomes in an affordable and sustainable manner. The integrated network development plan detailed in this AMP is designed to address the following key network constraints: around 10,000 consumers in Top Energy s northern area are reliant on a non-secure supply due to the fact that there is only one transmission line between Kaikohe and Kaitaia. These consumers are subjected to annual maintenance interruptions that can last up to 14 hours, as well as an elevated risk of unplanned fault interruptions, the sub-transmission system serving consumers in the Kerikeri area is loaded to its full design capacity at times of peak network demand. In the event of an unplanned outage of a sub transmission element, the network voltage could drop to an unacceptable level and this problem could only be addressed by shedding load, many of the assets purchased from Transpower are old and present safety and reliability risks. A major problem is the capacity and condition of the existing transformers at Kaitaia. These are old, single phase units that testing has indicated are in poor condition. They are also rated at 22MVA, which is less than the current peak load at the substation. The condition of the 33kV outdoor switchgear at both substations is also an issue, 13

16 EXECUTIVE SUMMARY load growth in some areas that are not well-served by existing zone substations is exceeding the capacity of the 11kV distribution system. The areas of particular concern are Kerikeri, the Whangaroa-Kaeo-Matauri Bay area and Russell, apart from Haruru, all zone substations are currently operated in a split bus, radial configuration in order to manage protection constraints. This does not meet Top Energy s security requirements for larger, two transformer substations, as it means that supply interruptions are inevitable, whenever a sub-transmission fault occurs, outdoor switchgear at some substations is in poor condition and requires replacement, in particular Moerewa and Waipapa, and the single phase transformer bank at Omanaia is now 58 years old and approaching the end of its economic life. The plan includes: construction of a new 110kV transmission line between Kaikohe and Kaitaia using a route around the east coast. This line will provide an alternative incoming transmission circuit to the northern region, it will also be used to supply Kerikeri and the coastal belt in the north east of the supply area. It will be commissioned as far as Wiroa in FYE 2016 and through to Kaitaia in FYE 2017, construction of a new transmission substation at Wiroa to supply the Kerikeri, Waipapa, Matauri Bay and Kaeo areas. This will be commissioned at 33kV in FYE 2014 and 110kV in Y2016, construction of new 33/11kV zone substations in Kerikeri and Martins Rd, Kaeo. The Kerikeri substation will be commissioned in FYE 2013 and the Kaeo substation in FYE 2014, replacement of the two 110/33kV transformers at Kaitaia in FYE 2015 with new larger units, replacement of the outdoor 33kV switchyards with new indoor switchboards at Kaikohe and Kaitaia transmission substations. The Kaikohe switchboard is planned for FYE 2014 and the Kaitaia switchboard for FYE 2018, refurbishment of the existing 110kV circuit between Kaikohe and Kaitaia during the period , reinforcement of the supply to Taipa through a second incoming circuit and the installation of two new, larger transformers by FYE 2019, installation of a newer, larger transformer at Omanaia by FYE 2019, reinforcement of the supply to the Russell peninsula, either through the installation of a third submarine cable from Paihia or possibly, as a temporary measure, the construction of a small power station, installation of a new fibre-optic communications system across the network to replace the existing, obsolete infrastructure and enable the use of modern protection and control technology, and upgrades to the 11kV distribution network to relieve localized overloads and to interface it to the new 33kV zone substations. 14

17 EXECUTIVE SUMMARY MAJOR PROJECT COST ($M) kV / 110kV line Kaikohe to Wiroa 6.8 Kerikeri Substation and Interconnections kV Line Upgrades (incl Waipapa #1 refurbishment) 3.8 Submarine cable to Russell kV Switchyard and switching station Wiroa kV Substation at Wiroa 5.2 Taipa Substation 5.4 Purerua Substation 2.5 Whatutwhiwhi Substation 1.9 Kaeo Substation and Interconections 7.4 Kaeo 33 kv Lines 2.7 Switchboard Replacement Kaikohe GXP 2.7 Switchboard Replacement Kaikohe GXP 2.7 Transformer Replacement Kaitaia kV Feeder Conversions - Taheke, Russell, South Rd 2.25 TE kv Line Wiroa to Kaitaia kV lines to Kerikeri Substation kv Line to Purerua kV line to new Taipa Substation kV Line to Whatuwhiwhi kV line No 2 to Omanaia 4.6 Figure 10: Major Project Implementation Timeline 15

18 EXECUTIVE SUMMARY Figure 11 below shows the planned layout of Top Energy s transmission and sub-transmission networks at the end of the planning period. Figure 11: Completed Architecture FYE2021 (forecast) Figure 12 below details the breakdown of expenditure by regulatory cost category. Where possible, projects have been optimised with respect to the required technical constraints and a desire to create a fairly flat and consistent work stream for our available technical and core skill resource. The graph also provides a comparison of actual and budgeted expenditure in FYE The significant jump in capital expenditure in FYE 2013 is due to the acquisition of the Transpower assets (around $7 million). 16

19 2011 (Budget) 2011 (Actual) 2012 (Budget) 2013 (Forecast) 2014 (Forecast) 2015 (Forecast) 2016 (Forecast) 2017 (Forecast) 2018 (Forecast) 2019 (Forecast) 2020 (Forecast) 2021 (Forecast) 2022 (Forecast) EXECUTIVE SUMMARY 40,000,000 35,000,000 30,000,000 25,000,000 20,000,000 15,000,000 10,000,000 5,000,000 - Fault and Emergency Maintenance Refurbishment and Renewal Maintenance Routine and Preventative Maintenance Capital Expenditure: Transmission Capital Expenditure: Asset Relocations Capital Expenditure: Reliability, Safety and Environment Capital Expenditure: Asset Replacement and Renewal Capital Expenditure: System Growth Figure 12: Expenditure Forecast (FYE 2011 to FYE2022) CAT EXPENDITURE DESCRIPTION FYE 2013 FORECAST ($K) CU Customer Connections 1,045 EX System Growth 11,822 RS Reliability, Safety and Environment 6,597 RR Asset Replacement and Renewal 3,000 Transmission 6,706 Capital Expenditure on Asset Management 29,169 MP Routine and Preventative Maintenance 3,560 MR Refurbishment and Renewal Maintenance 1,135 F Faults 1,200 Operational Expenditure on Asset Management 5,895 Total Expenditure 35,064 Figure 13: Expenditure Forecast Breakdown FYE 2013 With effect from 1st April 2011, Top Energy has increased its distribution line charges by an average of 22.3% across the tariff groupings, (7.4% after the application of posted discounts). This increase includes allowable CPI adjustments and an increase in Transmission pass through costs of approximately 14%. Figures 14 and 15 detail Top Energy s relative position with regard to Regulated Lines Business ROI and Annual Line Charge per ICP for FYE Top Energy s Peer Group of companies is shown in red and discussed further later in this section. 17

20 OtagoNet Joint Venture Electricity Ashburton Buller Electricity Westpower The Lines Company The Power Company Eastland Network Mainpower New Zealand Horizon Energy Distribution Marlborough Lines Alpine Energy Centralines Top Energy Vector Nelson Electricity Unison Networks Electricity Invercargill Powerco Wellington Electricity Aurora Energy WEL Networks Northpower Network Waitaki Counties Power Scanpower Network Tasman Waipa Networks Electra Annual Line Charges per ICP ($) Nelson Electricity OtagoNet Joint Venture Vector Wellington Electricity WEL Networks Aurora Energy Horizon Energy Distribution Eastland Network Network Tasman Waipa Networks Powerco Scanpower Electricity Invercargill Unison Networks Mainpower The Lines Company Electricity Ashburton Network Waitaki Electra Top Energy Alpine Energy Northpower Buller Electricity The Power Company Centralines Westpower Marlborough Lines Counties Power Return on Investment (%) EXECUTIVE SUMMARY Figure 14: FYE 2011 Regulated electricity lines business return on investment (Peer group of companies identified in red) 2,000 1,800 1,600 1,400 1,200 1, Figure 15: FYE 2011 Regulated electricity lines business: Annual Line Charges per ICP (Peer group of companies identified in red) 18

21 EXECUTIVE SUMMARY Industry comparison Top Energy has undertaken a benchmarking analysis of System Reliability and Performance indicators from within a justified peer group of rural and extensive rural NZ Electricity Lines Businesses (ELBs). The following criteria have been applied using the data from ELBs FY2011 Information Disclosures: larger than 15,000 customer base (i.e. eliminates Small Networks), less than 10 customers per km (i.e. eliminates Urban/Rural and Dense Urban Networks), and underground cable contributes less than 10% of the total system length (High Voltage and Extra High Voltage only, excluding Low Voltage circuits). ELBs chosen for the peer group are the following: Alpine Energy Marlborough Lines Eastland Network Northpower Electricity Ashburton The Lines Company Horizon Energy Distribution The Power Company MainPower New Zealand 19

22 BACKGROUND AND OBJECTIVES Section 2 Background and Objectives 2 B a c k g r o u n d a n d Ob j e c t i v e s Overview Purpose of this Plan Rationale for Asset Ownership Strategic Environment for Asset Management Planning Asset Management Planning and Implementation Strategic Planning Planning Periods Adopted Key Stakeholders Accountabilities and Responsibilities for Asset Management Asset Management Systems System Control and Data Acquisition Accounting/Financial Systems GIS System Network Analysis System Customer Management System Drawing Management System Ancillary Databases Maintenance Management System Business Processes and Information Flow Requirements Asset Data Accuracy Asset Inspections and Maintenance Management Network Development Planning and Implementation Network Performance Measurement

23 BACKGROUND AND OBJECTIVES 2 Background and Objectives 2.1 Overview Top Energy Ltd, formed in 1993, is an electricity generation and distribution business located in New Zealand s far north region. The business comprises four divisions: Ngawha generation, which operates the 25MW Ngawha geothermal power plant, Top Energy Networks (TEN), which distributes electricity throughout the Far North, Top Energy Contracting Services (TECS), which provides contracting services to the electric power industry, and Phoneplus, a contact centre business located in Kaikohe and Albany, Auckland. Top Energy is 100% owned by the Top Energy Consumer Trust, which holds the shares of the business for the benefit of power consumers connected to TEN s electricity distribution network. Top Energy is a major contributor to the community's financial well-being, managing assets with a regulatory base value of approximately $120 million and employing more than 200 staff. The company is one of the largest in the region and is uniquely placed to act as a catalyst for developing the region s economic potential. TEN distributes electricity to more than 30,000 electricity consumers in the territorial region of the Far North District Council. This AMP covers the management of TEN s fixed electricity lines and substation assets, which are located in an area from south of the Bay of Islands and Hokianga Harbours to the northern tip of the North Island of New Zealand. It does not cover the non-fixed assets of TEN or any assets managed by Top Energy Ltd s three other operating divisions. Assets covered by this AMP include a 110kV transmission line, two transmission substations, a 33kV sub-transmission network, eleven zone substations and forty-seven distribution feeders. The network is supplied with electricity from Transpower s transmission grid at the incoming circuit breakers at the Kaikohe transmission substation, also from the Ngawha geothermal power plant, which injects power directly into the 33kV sub transmission network. The figure below shows the network parameters as at 31 st March DESCRIPTION QUANTITY Area Covered 6,822km 2 Customer Connection Points 31,002 Grid Exit Points 2 : Kaikohe & Kaitaia 1 Embedded Generator Injection Points Network Peak Demand (to 31/12/2011) Electricity Delivered to Customers (FYE 2011) 1 : Ngawha Geothermal 70.7MW 327GWh Number of Distribution Feeders 47 Distribution Transformer Capacity Sub Transmission Cables (33kV) Sub Transmission Lines (33kV) HV Distribution Cables (22, 11 and 6.35kV) HV Distribution Lines (22, 11 and 6.35kV including single wire earth return) 251MVA 0.5km 263km 165km 2,738km Note 1: As of 1 April 2012, Kaikohe will be the only point where Top Energy takes supply from the Transpower Grid. Figure 16: Network parameters (as of 31 March 2011 unless otherwise shown) 21

24 BACKGROUND AND OBJECTIVES 2.2 Purpose of this Plan This AMP is a living document within TEN and lies at the heart of its asset management process. It is the integral tool for managing the long term capital and maintenance activities of the electricity network. The purpose of the AMP is to document the asset management processes and activities planned by TEN to meet agreed levels of safety, service and quality in the most cost-effective manner, In this context, the specific objectives for the AMP are to: define the services to be provided, the target service standards that TEN aims to achieve, and the measures used to monitor the performance of the services delivered, translate Top Energy Ltd s business objectives and strategic goals into asset management strategies and action plans, as they relate to the electricity network. The plan identifies the forward works programmes required to meet agreed service levels, cater for future growth and estimates the current cost of delivering these programmes, demonstrate responsible management of the network infrastructure, funds are optimally applied to deliver cost-effective services that meet customer expectations, document current asset management practices used by TEN as part of a sustainable and optimised lifecycle management strategy for the network infrastructure, identify actions that enhance management performance, and achieve compliance with clause 7 of the Electricity Distribution (Information Disclosure) Requirements As stated in Top Energy s Statement of Corporate Intent, the AMP is the defining document for Top Energy Ltd s network business and sets out the 10 year capital and maintenance expenditure levels required to ensure that the network is managed in a sustainable way. The AMP also includes TEN s network performance targets, areas of network business focus and development, and its approach to risk management and contingency planning. It is based on the current understanding of consumers requirements and asset conditions, and is intended to demonstrate to all stakeholders that Top Energy Ltd manages its network assets safely and responsibly. The AMP also details macro-level strategies for the various asset classes for the planning period. Where necessary, changes and modifications will be made to the AMP to reflect the dynamic nature of the business and its operating environment. Maintaining an accurate AMP also provides a resource for a whole-company understanding and approach to effective asset management. Protection of stakeholder interests is achieved through the application of business management and risk management processes founded in Top Energy Ltd s Statement of Corporate Intent. In particular, the AMP seeks to ensure that: there is a link between corporate strategy and the management of network assets, capital expenditure decisions are prudent and represent value to consumers, asset replacement and network augmentation is undertaken with appropriate timing, an optimal life cycle approach is taken to managing network assets, asset management strategies reflect the expectations of stakeholders, including customers, TEN meets legal and regulatory requirements, a long term view is taken to developing annual budgets and work plans, asset management strategies support revenue requirements and deliver a reasonable profit, in keeping with both shareholder expectations and regulatory constraints, best practice performance in the management of direct and indirect operating and maintenance costs is achieved, appropriate risk management practices form an integral part of normal business activities, and 22

25 BACKGROUND AND OBJECTIVES ethical behaviour is practised in everything that is done, particularly during all stakeholder interactions. 2.3 Rationale for Asset Ownership The assets covered by this AMP are utilised by TEN to deliver electricity to consumers within its supply area. The majority of these assets were originally installed as part of a distribution network designed to provide an electricity supply at minimum cost to consumers living in a large, sparsely populated and economically deprived area. At the time, supply availability was considered more important than reliability and cost was an overriding consideration. Hence the network is characterised by a small number of long distribution feeders, supplied from a limited number of zone substations. Two wire and single wire earth return lines were used extensively. Unfortunately, the existing network was never designed to supply the level of reliability of a modern, developed economy and what consumers now expect. While there have been modest improvements in supply reliability as a result of better maintenance practices and the installation of strategically targeted network automation and remote control devices, the overall reliability remains amongst the lowest in the country. In order to significantly improve supply reliability, the network architecture needs to be upgraded. Firstly, by providing a second high capacity incoming supply to serve customers in the north of the supply area. Secondly, by providing more points of injection into the medium voltage distribution system. These improvements would have the following benefits: customers the northern region would continue to receive an electricity supply when the existing incoming line is out of service through planned maintenance or as a result of an unplanned fault, increased utilisation of the existing medium voltage network assets, improved reliability of supply by providing for an increased number of shorter distribution feeders, each supplying fewer consumers. This would reduce the average number of consumers affected by a single fault and often allow earlier restoration of supply to customers not directly affected, and improved network voltages, increasing the quality of supply to customers located in remote areas. Section 5 of this AMP presents an ambitious 10 year development plan that, when completed, will provide a network with sufficient capacity to meet electricity demand in the medium term and beyond, with a reliability of supply comparable to that enjoyed by electricity consumers in other parts of the country. This development plan will require substantial investment which, in the opinion of the Top Energy Consumer Trust and the Top Energy Board, is necessary to deliver the requisite service to consumers and support the on-going economic development of its supply area. 2.4 Strategic Environment for Asset Management Planning Top Energy s corporate mission statement outlined in the Statement of Corporate Intent (SCI) is: To operate a successful and responsible business and to maximise the value of the Group in the long term for the benefit of the Shareholders. The key SCI actions relating to network asset management are: achieving network service quality standards acceptable to the community and deliverable from future maintainable earnings of the network business, 23

26 BACKGROUND AND OBJECTIVES developing and utilising staff skills and the Group s intellectual property, while providing a safe environment for staff, contractors and the public, operating in accordance with the principles of environmentally sustainable management, and acting responsibly and co-operatively in the community and adopting a responsible approach to social and cultural issues. These actions are incorporated into this AMP. The target network service quality standards in the SCI are also consistent with those adopted in the AMP. The following business objectives have been adopted by the Board and provide a framework for asset management within TEN, which align with the SCI: Top Energy maintains a good relationship with its external stakeholders, including its owner and customers, the network return on investment (ROI) is maintained relative to the acceptable regulatory band, which reflects the cost of capital, the network is developed according to the network development plan, which is detailed in this AMP, the network is maintained according to the maintenance plan, which is detailed in this AMP, asset and business risks are understood, communicated and controlled, reliability is within realistic expectations, relative to an appropriate peer group, supply capacity is available to allow economic growth in the Far North, security of supply standards are met or the risks are understood with a contingency plan in place, capabilities are increased in people, process and systems, standards are defined across the network, and there is an aligned team that are high performers and proud to work for Top Energy. 2.5 Asset Management Planning and Implementation Strategic Planning The company maintains a number of internal and external planning documents that connect with the AMP, including: Statement of Corporate Intent (SCI), which is agreed between the Trustees and the Directors on an annual basis. This document outlines the company s strategic performance targets and incorporates the outcomes of the annual strategic business review, regulatory disclosure documents, including those associated with information disclosure, financial accounts and the Commerce Commission s price-quality threshold regime, Risk Management Manual. The framework and analysis process for the identification and mitigation of business risks across the organisation, Annual Plan/Budget. A short-term operating document detailing the current activity budgets approved by Directors,, monthly Board Reports, which update Directors on progress against the Annual Plan and detail other issues that they need to be aware of and/or approve,, Emergency Preparedness Plan, detailing Top Energy s network management and associated practices adopted to ensure electricity supply is maintained or quickly restored following emergency circumstances and events,, and Northland Region Civil Defence Emergency Group Plan (NRCDEGP), which describes procedures for the response to a civil defence emergency in the Northland region. 24

27 BACKGROUND AND OBJECTIVES The NRCDEGP identifies interdependence issues with the Top Energy network and other lifelines,, and the role of Top Energy in the response to a civil defence emergency. The response procedures include the operation of injection equipment and support delivery to ensure the functioning of the MEERKAT community warning system. While strategic corporate objectives influence the direction of the AMP, the AMP in turn forms a key input into the detailed corporate planning process. The AMP is an integral part of a circular planning process that is carried out and updated annually to determine the strategic direction that Top Energy adopts, optimising the benefits to all stakeholders and to ensure that the strategy remains relevant over time. Company planning cycle This process begins with a strategic review of the company s business, performed by the Board and executive management team to determine Top Energy s medium and longer-term operational and financial strategies at a high level. It includes an analysis of the financial position of the network business, based on the forecast expenditures in the current AMP and updated as necessary to reflect changes in the environment within which the business operates. The SCI, which is agreed between the Trustees and the Board, is prepared in parallel with the strategic review and, amongst other things, formally documents the key objectives and targets of the network business. These objectives and targets are reflected within the AMP, which consolidates the various development and maintenance plans into a single asset management planning document for use by external stakeholders and Top Energy employees. The first year of the AMP budget forms TEN s budget and work programme for that year. The remaining annual budgets of the AMP planning period are forecasts and reflect expectations at the time as to how the external environment will evolve over the planning period. As these budgets are less certain, they will be updated in subsequent editions of the AMP, published annually. The annual work plan is managed and delivered by the network management team. However, all projects over $500,000 are also subject to Board approval before commencement. This is carried out via a detailed project proposal paper that is submitted to the Board for approval. The outcome of the paper (approval/rejection) is formally recorded in the monthly Board meeting minutes. TEN s management team manages the delivery of the annual work plan though the day-to-day management of contractors and consultants,, primarily Top Energy Contracting Services (TECS). Progress against the plan is reported by TECS on a weekly and monthly basis to the relevant section manager in charge of the delivery function within the network management team. In turn, this progress is reported on a weekly basis to the General Manager Networks, who then reports to the Board on a monthly basis. Towards the end of each calendar year, TEN s management team reviews expected performance against the current annual work plan and the extent to which the strategies, targets and expenditure forecasts set out in the AMP remain relevant,, given the changes to the environment within which the network business operates. The gaps identified form an input to the strategic review for the following years and the circular planning process repeats itself Planning Periods Adopted This AMP is dated 1st April 2012 and relates to the period from 1 April 2012 to 31 March It was approved by the Top Energy Board on 27 th March 2012 and replaces all previously published AMPs Key Stakeholders Top Energy engages with stakeholders through the following forums: meetings and informal discussions,, discussions with major customers,, industrial seminars and conferences,, 25

28 BACKGROUND AND OBJECTIVES customer surveys,, enquiries and/or complaints,, discussions with the Top Energy Consumer Trust,, reviews of major events (e.g. storms),, specific project consultation (e.g. capital projects),, meetings with suppliers,, performance review and management for internal and external contractors,, papers and submissions,, and local media. The Figure below indicates how the AMP reflects, and helps Top Energy address, the expectations of different stakeholders. Each revision of the AMP is made available to all stakeholders for their consideration and their input is welcomed at any time. Where conflict arises between Asset Management requirements and stakeholder expectations, TEN aims to achieve an optimised outcome that is acceptable to all affected stakeholders. In these situations, the following considerations apply: safety is always the highest priority,, the needs of all affected stakeholders are considered,, balance is sought between the cost of non-supply and the investment needed to provide the desired level of reliability,, and alignment with the objectives published in the Statement of Corporate Intent. If a conflict between different stakeholders still exists after the normal course of business, an appropriate resolution process is adopted to resolve any concerns and arrive at a solution acceptable to the parties concerned. Such situations most often arise because stakeholders do not have a complete understanding of all the issues and these can usually be resolved by working closely with the parties concerned to achieve an acceptable outcome. However, if agreement cannot be reached, TEN will proceed in a manner that it believes is fair to all the affected parties and consistent with Top Energy s values and objectives. 26

29 BACKGROUND AND OBJECTIVES STAKEHOLDER EXPECTATIONS CURRENT DATA SOURCE MEASURES ACTIONS CUSTOMERS RETAILERS Fair Price Reliability Commerce Commission, Pricing Spread sheets/ Budgets Billing System, DigSilent (Network Analysis Software) Regulatory Threshold Loss Factors OPEX and CAPEX expenditure is controlled and managed against the Annual Plan (which is consistent with the AMP) to ensure profitability and service levels are maintained within revenue constraints. Network losses are measured and planning and design activities ensure they are maintained at an optimum level. Loss factors for different parts of the network are calculated in accordance with the methodology approved by the Electricity Authority. SCADA, GIS, DigSilent Asset Utilisation Planning and design activities ensure optimum asset utilisation. Financial System, SCADA System, DigSilent PriceWaterhouseCoopers Report Reliability Database, SCADA, GIS, Defects Management System GIS, DigSilent Transpower Costs Lines Business Rankings SAIDI, SAIFI Security Standards Quality Faults Register Voltage Complaints Communications Communications Simple tariff CMS System (Call Management System) Fault records, SCADA and GIS Use of Systems Agreement and Industry Regulations Regular face-to-face meetings or telephone conferences Call Centre Statistics Outage data transfers Tariff Changes Agreements from Retailers GXP demand is actively managed to ensure connection costs are controlled. Network performance is assessed for reasonableness through comparison with peer group disclosures. Reliability is continually measured and reviewed against targets detailed in the AMP. Work aimed at improving reliability is targeted at known causes of poor reliability. Projects are identified to address present and future non-compliance. Modelling and actual customer complaints identify problem areas and voltage improvement projects are implemented as a result. The Top Energy owned contact centre (Phoneplus) ensures customers are directed to the appropriate point of contact for quick and efficient service. TEN shares information in accordance with standard industry protocols. Top Energy coordinates the timing of any tariff changes with retailers. The current tariff structure has been developed in conjunction with retailers and reflects the business needs of all parties. 27

30 BACKGROUND AND OBJECTIVES STAKEHOLDER EXPECTATIONS CURRENT DATA SOURCE MEASURES ACTIONS BOARD TOP ENERGY CONSUMER TRUST Open Network Access Allocation of Losses Metering and Billing Safety Industry Regulations and Transparency Monthly Loss Data and Network Analysis Software ICP Database, Retailer Records and Systems Industry Regulations and Standards Published Plans and Price Methodology 12 month rolling losses Random Audits of Retailers Systems and Sites Accident Report Stats and Non Compliances Profit Financial System Audited Financial Reports Accountability Compliance Social Responsibility Key Performance Indicators Correspondence and Board reports GIS and Financial system Annual Staff and Plan Performance Reviews Legal and Statutory Compliance Capital Contribution Scheme Dividend Financial System Audited Financial Reporting Grow Asset Value Financial System, GIS Asset database Annually Disclosed Asset Valuation Retain Ownership Survey Report Ownership Reviews as per SOI Top Energy has a transparent pricing structure that is well explained. Loss factors for different parts of the network are calculated in accordance with the methodology approved by the Electricity Authority. Top Energy relies on the retailers systems to reconcile revenue. Safety is accorded the highest priority,, TEN operates a safety management system that has received acclaim from the industry. Safety outcomes are actively monitored and reported monthly to the Board. Financials are reported monthly to the Board. This report includes a comparison against the approved budgets in the Annual Plan. TEN employees key performance indicators are linked to asset management service levels. Internal standards, procedures and policies. Equitable sharing of costs. Operating and capital expenditure is controlled and managed against the Annual Plan to ensure profitability and service levels are maintained. Timely investments are made to meet customer needs with long-term valueadding assets. Overlay the desire of the shareholder for local ownership with a strong commitment for improving service levels and maintaining profitability. 28

31 BACKGROUND AND OBJECTIVES STAKEHOLDER EXPECTATIONS CURRENT DATA SOURCE MEASURES ACTIONS REGULATOR STAFF PUBLIC COUNCIL Figure 17: Compliance with Regulations under part 4A of Commerce Act Legislation and Correspondence Monthly Reports and Forecasts Against Thresholds Health and Safety Safety Database Accident Report Statistics Job Security and satisfaction Training Safety Vegetation Control is Fair Land access rights upheld Resource Management Road Management Administration Spread sheet Administration Spread sheet Industry Regulations and Standards Spread sheet, GIS Reliability Database, SCADA, GIS Staff Survey Results, Staff Turnover Figures Agreed Professional Development Accident Report stats and Non Compliances Complaints and Service Levels Fault Statistics Forms an integral part of monthly reports to the Board. Internal standards, procedures and policies. Ensures that a succession plan is in place so that relevant skill sets will be available when required. AMP reflects the skill set required, which inputs to the Training and Development Plan. Staff training hours are monitored and disclosed in Top Energy s Annual Report. TEN operates a safety management system that has received acclaim from the industry. Only pre-qualified contractors are permitted to work on the network. Targeted vegetation control expenditure in accordance with the defined service levels and Tree Regulations. Targeted expenditure. CMS system, GIS Complaints The AMP identifies future work, which allows TEN to consult with stakeholders and comply with relevant regulations. Legislation, GIS Procedures, GIS Consents for Work Consents for Work Marine Crossings Procedures, GIS Consents for Work Relationship between Stakeholders and AMP The network development plan acknowledges time frames for consent processes. The network development plan acknowledges time frames for consent processes. The network development plan acknowledges time frames for consent processes and on-going costs 29

32 2.5.4 Accountabilities and Responsibilities for Asset Management BACKGROUND AND OBJECTIVES The Top Energy Consumer Trust is the sole shareholder of Top Energy Ltd. The shares are held on behalf of electricity consumers connected to the Top Energy network,, and the Trust appoints the Top Energy Board of Directors to carry out the governance and management functions of the business on its behalf. The Top Energy Board governs the asset management effort through the development of strategy, approval of the annual plan and budget and through regular monitoring of the operations of all divisions, including TEN and TECS. The Board also has input into performance targets delivered for signoff by the Trust,, and individually approves all capital expenditure projects with an estimated cost of $500,000 or more. Figure 18: Top Energy Structure The Board appoints the Chief Executive Officer who, with his staff, controls the asset management effort through the normal course of business. TEN is the operating division of Top Energy directly responsible for management of the network assets covered by this AMP. TEN is managed by the General Manager Networks, who reports to the Chief Executive Officer and follows the strategies and policies determined by the Board. TEN is responsible for ensuring that the network assets are developed, maintained, renewed and operated on a long-term, sustainable basis,, ensuring that electricity is distributed to customers with an appropriate quality and reliability in accordance with the objectives and requirements of the Top Energy Consumer Trust. TEN is responsible for determining revenue requirements, maintaining asset records, developing and setting standards, operating the network in a safe manner to minimise outages, monitoring performance, making investment recommendations, managing risk, and for the on-going management of the network assets in line with yearly renewal, maintenance, capital and operational expenditure budgets. In particular, TEN is responsible for updating the AMP and implementing the annual plan for the Networks Division, as approved by the Board and reporting on its asset management activities to the Board on a monthly basis. TEN is required to report material departures from the annual plan in terms of scope or financial over-runs, together with all variations to projects with an agreed budget of 30

33 BACKGROUND AND OBJECTIVES $500,000 to the Board at the first available monthly meeting. However, departures from the annual plan affecting projects costing less than $500,000 are discussed and agreed between the General Manager Networks and the Chief Executive Officer,, although they may also be raised for Board discussion and approval if they are considered significant in relation to future projects or the overall achievement of the annual plan. Apart from specialist activities, work on the network, including major construction projects, is undertaken exclusively by TECS,, which employs around 95 staff comprising supervisors, electricians and lines staff. TECS operates from purpose-built depots in Kaitaia and Puketona. While TECS is also a division of Top Energy, work contracted-out to TECS is managed by TEN as if it was an external contractor. An armslength relationship is maintained by established Chinese Walls around key operational and financial information between the divisions. The cost of field work is comparatively benchmarked against current industry costs to ensure efficiency of works delivery is maintained. The Top Energy Consumer Trust and the Board believe that this arrangement is in the best interest of Trust beneficiaries since, with this model, the interest of the asset manager and service provider are fully aligned. The degree of autonomy accorded to TECS depends upon the nature of the work. Large capital projects are managed directly by TEN staff,, although TECS is able to prioritise routine maintenance activities and minor capital works, provided it works within the budgets set out in the approved annual plan. TEN monitors the work undertaken by TECS through weekly and monthly reports on work progress and financial performance against budget,, this is included in the General Manager Network s monthly Board report. Specialist work outside the skill set of TECS staff is outsourced to external contractors and supervised directly by relevant TEN maintenance, planning or operations managers. Top Energy operates a Safety Management Plan and in 2011 won the Electricity Engineers Association (EEA) Workplace Safety Award. Consistent with the requirements in Safety Manual Electricity Industry (SM-EI), TEN implements an Authorisation Holders Certificate (AHC) assessment process to ensure the competence level of field staff (both internal and external) is compliant with company and industry standards. Staff are required to be assessed on their competency on a 12 monthly basis, in order to work on the network. Staff must provide relevant training records, workplace audits, and operational evidence to prove their competency in undertaking specific tasks. The AHC holder is only allowed to perform the tasks to the level permitted after the assessment and approval for issuing an AHC to an individual is by recommendation of the Network Operations Manager and consent of the General Manager Networks. The structure of TEN s asset management team is outlined in Figure 19 overleaf. 31

34 BACKGROUND AND OBJECTIVES Figure 19: Top Energy Network Division - Structure The key responsibilities of senior management staff within the TEN team are: Position General Manager Networks Maintenance Manager Planning Manager Programme Delivery Manager Manager Asset Information Systems Operations Manager Engineers Accountability To control the overall, annually approved network budget. Approximately $28 million. To control the overall, annually approved maintenance and renewal budgets. Approximately $8 million. To control the overall, annually approved capital budgets. Approximately $20 million. To manage the delivery of the capital investment programme. Budgets assigned as per individual projects. To manage the GIS department budget to ensure the asset data integrity is maintained. To manage the control centre and fault budget, and monitor network performance. Delegated authority to manage projects to individual budgets. Figure 20: Top Energy Network Division Responsibilities 32

35 BACKGROUND AND OBJECTIVES Individual order approval levels are: CEO $1M General Manager Network $100k Section Managers $30k Engineers Nil present authority Figure 21: Top Energy order approval levels 2.6 Asset Management Systems The Top Energy Group uses a range of information and telecommunications systems critical to the asset management process. This section outlines Top Energy s present and future development plans for information systems System Control and Data Acquisition TEN uses the ipower SCADA system for operational, real-time load data-gathering requirements, load control and logging and reporting state changes from controllable devices. The system provides for circuit breakers at all TEN zone substations, as well as the 33kV feeder circuit breakers at Kaikohe and Kaitaia GXPs, to be remotely operated from the central control room at Kaikohe. In addition, it is possible to remotely operate switches and reclosers situated at strategic locations throughout the medium voltage distribution network. SCADA monitoring and control of the Transmission circuit breakers and ancillary equipment in Kaikohe and Kaitaia GXP s will remain through Transpowers Northern Regional Control Centre in Auckland and will be transferred to Top Energy s SCADA system in FYE2014. The SCADA system also records system and feeder half-hour demand information, which is available via the company s intranet for further analysis and processing in separate systems Accounting/Financial Systems The Top Energy Group uses Microsoft Navision financial software for the management of expenditure, capital accounts, estimating capital jobs, inventory, orders, and accounts payable and receivable. The company uses Payglobal for processing all salaries. Reporting of actual versus budget performance occurs on a monthly basis by general ledger category and individual projects. The senior management team also receive monthly reports of: profit and loss reconciliation by division, consolidated profit and loss, consolidated balance sheet, consolidated cash flow, and capital and maintenance expenditure. Top Energy also uses ancillary electronic databases and spread sheets to analyse the performance of the company. These are used for setting the budget revenue requirements and for tracking progress against budget. The company s Navision financial system is used to invoice and track payments from customers and retailers GIS System The Intergraph Geographic Information System (GIS) acts as an engineering asset register and provides a spatial representation of assets, their relationships with one another, customers and 33

36 BACKGROUND AND OBJECTIVES vegetation. This information is merged with the Terralink base and overlaid with raster images from aerial photography. The GIS data has several integrated critical business applications that are used to manage and report on assets. These are: ICP Application An application that is integrated into the national registry to manage and report on customers Installation Control Points (ICPs). Supplementary information is included to facilitate Top Energy s management of customer connections, including safety and pre-connection status. Permission Applications Used for storing details and agreements relating to easements and general property access rights. Incidents/Faults Management System Where the location of a fault is noted against an asset that has failed. The application provides electrical traces to be run to ascertain the areas, roads and numbers of customers affected under different switching configurations. This is used to generate the network s SAIDI, CAIDI, SAIFI statistical performance reporting Network Analysis System A DigSilent systems analysis package is used for load flow, voltage profile and protection design. It also has provision for harmonic and stability analysis. The DigSilent package directly interfaces with the GIS system to ensure that the analysis uses an accurate network model. This provides a powerful tool for the analysis of load growth, development options and the impact of unusual switching operations Customer Management System Top Energy s subsidiary Phoneplus is contracted to handle customer calls and uses its Customer Management System (CMS) to provide Top Energy with details about specific customer calls and call statistics Drawing Management System Top Energy uses Bentley s MicroStation CAD software to generate construction drawings for subdivisions and new capital works. In addition to the above, CAD drawings include: zone substation building and site plans, specialised equipment drawings, procedures manual diagrams, and control, circuit and wiring diagrams Ancillary Databases Top Energy uses a number of ancillary databases and standard MS Office products such as MS Access and Excel for: maintenance management, long-term renewal, augmentation and maintenance planning by asset category, outage data and fault statistics, managing and reporting monthly performance data, and management of capital and maintenance projects. 34

37 BACKGROUND AND OBJECTIVES Maintenance Management System Condition-based defect data and asset management schedules are currently managed within GIS using a maintenance management database developed in-house and controlled by the maintenance management team. Top Energy now plans to purchase proprietary asset management software in FYE 2013 to replace the in-house database. This software will provide a repository for recording asset condition information and will provide a range of planning and management functions not available in the existing software. 2.7 Business Processes and Information Flow Requirements The diagram below represents the data sources, data storage locations and information flows used by Top Energy network staff when carrying out asset management planning and delivery. Figure 22: Maintenance planning information flows Asset Data Accuracy TEN maintains a dedicated GIS team that is responsible for ensuring that asset data is accurately recorded and maintained. A system is in place that records errors noted by Top Energy staff during using the GIS database during the course of their work. These errors are collated into a spread sheet and returned to the GIS team for correction. GIS data is considered to be highly accurate in the following areas: 11kV Lines and associated equipment transformers (overhead and ground mount) line switchgear and equipment low voltage service boxes and link pillars 33kV zone substations 33kV lines 33kV switchgear 35

38 other technical equipment including SCADA 11kV cable and related equipment including switchgear 33kV cable and related equipment including switchgear BACKGROUND AND OBJECTIVES For these asset types, individual assets down to mother/child connectivity levels are identified and attributes, capacity and condition data are recorded. Some data gaps and errors exist with respect to: low voltage systems, and customer points of connection (i.e. 3 phase, single phase, underground or overhead). A focus is now being put on collecting the missing data as part of the asset inspection program. However, the impact of remaining errors within GIS will have a minimal impact on the reliability of the information presented in this AMP for the following reasons: 1. asset data is spatially accurate due to a systematic program of GPS plotting of assets during the FYE , 2. more critical 11kV and sub-transmission data has already been corrected, 3. errors relate to the low voltage network, much of which is privately owned and outside the scope of this AMP, 4. customer ICP data is accurate and linked to a specific asset cluster for performance reporting, therefore system connectivity is accurate, and 5. results of several rounds of lines inspections have been entered, therefore conductor, transformer and other equipment types are correct, allowing calculations for future development and loading to be confidently assessed Asset Inspections and Maintenance Management TEN has developed a time-based asset inspection programme that covers all system assets with inspections undertaken by contract asset inspectors. The frequency of inspection under this programme is based on the expected rate of asset deterioration and a risk-based assessment of the consequences of an asset s failure. It is complemented by a structured time-based, non-invasive condition assessment programme that targets key assets (e.g. power transformers) as well as items that are prone to failure (e.g. cable terminations). Defects identified during asset inspections and condition assessments are prioritised and recorded in a maintenance management database developed in-house. Defects are prioritised by TECS and actioned directly within approved budgets and performance targets. This allows TEN s maintenance management section to focus on strategic maintenance issues. Quality and efficiency is monitored through selective auditing and monthly reporting. TEN receives regular reports from TECS on maintenance work undertaken. These are used by the General Manager Networks as the basis for Board reporting on maintenance work undertaken and expenditure against the maintenance budget. TECS also operates a 24-hour emergency maintenance service to provide prompt repair of network faults and to promptly attend to defects that pose an immediate threat to public safety. Network maintenance strategies are discussed in greater detail in section 6 of this plan Network Development Planning and Implementation During 2009, TEN undertook a review of the risks associated with the available network capacity, performance and security of supply levels. An interface was also developed between the GIS system and the DigSilent network analysis software, which has allowed the development of a detailed and accurate model of the network for system analysis. This model, together with recorded SCADA information, future load growth predictions and asset defect, condition and attribute data, is now used to accurately determine the present utilisation of network assets and to identify areas of the present network unable to meet forecast load growth with an acceptable security of supply. 36

39 BACKGROUND AND OBJECTIVES This analysis, coupled with a forecast of future demand, is used to prepare the Network Development Plan presented in section 5 of this AMP. This is reassessed on an annual basis after the load forecast is updated, taking into account the actual peak demand on the network that normally occurs in August each year. The actual network demand is checked against the previous forecast to ensure that network growth is being realistically and accurately determined. Where necessary, demand projections are modified. The fundamental assumptions made in the formulation of the Network Development Plan are also reviewed for their on-going validity, to ensure the plan efficiently and effectively addresses security, reliability and capacity issues. The reassessment typically results in adjustments to the timing of planned development projects and may involve the redesign of some projects to accommodate new loads or developments that have been accelerated, cancelled or deferred. Project budget estimates are also reviewed annually and adjusted for changes in construction cost and the impact of more accurate resource consenting and easement costs Network development capital projects are carried out by TECS with the exception of some specialist services, such as ground fault neutraliser (GFN) installation. Load forecasting and the development of the network capital investment strategies are discussed in greater detail in section 5 of this plan Network Performance Measurement Top Energy has developed an internal Faults Management System called Whiteboard. Once a call is received by the control room staff, a fault job is raised within Whiteboard. This details information such as time raised, location, dispatcher notified, team details, on-site arrival, site departure and work carried out. This provides a detailed fault analysis tool for tracking, managing and post fault analysis of all network fault events, including determination of SAIDI and SAIFI statistics. Whiteboard also provides a list of faults with active or incomplete status, so that Top Energy can follow up to ensure service attendance was achieved. In addition to Whiteboard, operational fault and switching times are logged for each fault event by the Network Control Centre staff within the operational log. Together with SCADA, this information is used to run a GIS query for each fault to determine the numbers of customers affected at each stage of the fault and, subsequently, the SAIDI and SAIFI impact for each fault event. For each fault that has an impact on SAIDI, there is an individual switching record created. Each record is then entered into a database that contains the necessary data to generate an outage report, to provide statistical data for use in producing accurate performance reports. This information is also used for statistical failure mode data analysis that can be used for maintenance and future fault prevention planning. Monthly and annual audits are carried out on all fault calculations. In the event of an error, a wider sample (or the entire population) is audited. Annual audits are also carried out by an external audit consultant. 37

40 BACKGROUND AND OBJECTIVES Figure 23: Screenshot of the Faults Whiteboard Network performance measurement and tracking is the responsibility of the Network Operations Manager. Monthly fault statistics, together with SAIDI, SAIFI and CAIDI performance, are prepared for inclusion as part of General Manager Network s monthly Board report. Further details and discussion on network performance monitoring is presented in Sections 4 and 8 of this Plan. 38

41 ASSET DESCRIPTION Section 3 Asset Description 3.1 Overview Distribution area Load characteristics and large users Sub-transmission system Distribution system Secondary assets Protection SCADA and communications Load control system Asset Details by Category Overhead conductors Sub transmission Distribution Low Voltage Poles and Structures Sub-transmission Distribution Low Voltage Underground Cables Sub-transmission Distribution Low Voltage Submarine Cables Streetlight Cables Distribution Transformer and SWER Transformers Reclosers Regulators Ring Main Units (RMU) Sectionalisers Capacitors Zone Substation Equipment Power Transformers & Tap-changers Circuit breakers Zone Substation Structures Zone Substation DC Systems Zone Substation Protection

42 ASSET DESCRIPTION Zone Substation Grounds and Buildings Customer Service Pillars SCADA and Communications Load Control Plant Justification for Assets Grid Exit Point (GXP) Sub-transmission network Northern Network Southern Network Zone Substations Distribution network Distribution transformers Low voltage network Voltage control devices Load control plant SCADA equipment Spares

43 ASSET DESCRIPTION 3 Asset Description 3.1 Overview Distribution area Top Energy manages the northern most network in New Zealand, covering an area of 6,822 square kilometres, bounded by the east and west coasts and the territorial local authority boundary of the Far North District Council in the south. Figure 24: Top Energy area of supply The majority of the district s land area is rural. There is no single dominant urban area, with urban development spread amongst several towns with populations between 1,000-6,000 and numerous smaller settlements. Coastal settlements, especially on the eastern and north-eastern coasts, are growing at a faster rate than the district average. Most inland settlements, such as Kawakawa, Moerewa and Kaikohe, have relatively static, and in some instances declining, populations. Top Energy provided services to 31,002 connection points as of 31 March Compared to New Zealand as a whole, the district is notable for a high proportion of people who are either on low incomes or unemployed, and have lower rates of educational achievement. Consequently, in the year ending March 2010, the average quantity of electricity supplied to each connection point was the second lowest in the country, notwithstanding the impact of the large Juken Nissho Mill load Load characteristics and large users For FYE 2011, the maximum demand was 70.7 MW. The total energy delivered to customers in FYE 2011 was 327 GWh. The majority of electrical load is residential, small commercial and agricultural. There are only five large users: Juken Nissho Mill at Kaitaia ( 10.6MVA), AFFCO Meat Works near Moerewa ( 2.4MVA), 41

44 ASSET DESCRIPTION Mt Pokaka Timber Products Ltd, south of Kerikeri ( 1.2MVA), Immery s Tableware near Matauri Bay ( 1.1MVA),and Northern Regional Corrections Facility at Ngawha ( 0.6MVA). Top Energy s three largest consumers, have dedicated supply feeders from a local zone substation, but Immery s Tableware and the Ngawha Corrections Facility are supplied at 11kV from their local distribution feeder. Maintenance, renewal and replacement strategies for assets that affect the operations of major consumers are discussed and negotiated with the individual company. As a result, maintenance work affecting these consumers is usually scheduled for their off-peak or non-operational periods. Top Energy also works closely with its major customers to ensure that the service that it provides is aligned with their requirements, to the extent feasible on a shared network Network Characteristics Energy from the national grid is delivered to the Kaikohe transmission substation through a double circuit 110kV Transpower-owned transmission line and the points of injection into Top Energy s network are the 110kV incoming circuit breakers at the Kaikohe substation. Power from the 25MW Ngawha geothermal power station, situated about 7km south east of Kaikohe, is also delivered to Kaikohe though 33kV TEN sub-transmission lines. Top Energy s supply area is separated into two distinct geographic areas: the northern area including Kaitaia, Taipa, and the far north peninsular, is supplied from a 110kV transmission substation located at Pamapuria, approximately 10km east of Kaitaia. The more heavily loaded southern area (including Rawene, Kaikohe and the coastal towns of Kerikeri, Paihia and Russell) is supplied from Kaikohe. A single circuit 110kV transmission line, which crosses the Maungataniwha Range, connects the two substations, but there is no interconnection at sub-transmission voltage. A 33kV subtransmisson network supplies eleven zone substations, four in the northern area and seven in the southern. The zone substations in turn supply a total of 47 distribution feeders, which generally operate at 11kV. In rural areas, many spur lines fed from distribution feeder backbones are two wire single phase or single wire earth return. Approximately 20km of the Rangiahua feeder in the southern area has been uprated from 11kV to 22kV operation. Low voltage (LV) distribution is at 415V 3-phase, 480/240V 2-phase and 240V single phase. The key weaknesses are: a single 110kV between Kaikohe and Kaitaia, which means that all supply to consumers in the northern area is lost when this circuit is not available, under-sized transformer banks at Kaitaia substation. In the event of a loss of one of these banks at times of peak load, supply to consumers in the northern area will need to be rationed, single circuit supplies to Omanaia, Pukenui and Taipa, and Kaikohe zone substations, although the supply to the Kaikohe zone is a short overhead tie line, capacity constraint issues at Waipapa substation. The ability to maintain an acceptable voltage level in the Kerikeri area is marginal if one of the two sub transmission lines supplying Waipapa zone substation is lost. Furthermore, if one of the Waipapa transformers was lost at a time of peak load, supply may need to be rationed until the mobile transformer was relocated to avoid overloading the remaining transformer, protection constraints that currently require all 33kV lines and substations to operate in a radial configuration. This results in an unavoidable loss of supply to some customers if any sub transmission element should fail, and transformer capacity constraints or a lack of redundancy mean that n-1 transformer capacity either does not exist or will be lost during the planning period at Omanaia, Kawakawa, Waipapa, Taipa and Pukenui, assuming no action is taken. This means that supply cannot be fully restored, even after switching, following a fault until the fault is repaired or the mobile transformer relocated. 42

45 3.1.4 Grid Exit Point With the acquisition of the transmission assets, Top Energy s only GXP is the termination of the Transpower 110kV Maungatapere- Kaikohe circuits. Transpower retains ownership of the two 110kV circuit breakers at Kaikohe that terminate these circuits, each of which has a winter rating of 77MVA. With one circuit out of service, the second circuit would be fully loaded by 2017, should Top Energy draw all of its supply off the grid. Generation, such as from Ngawha, reduces the circuit loading and consideration of the need for thermal upgrades to the incoming Transpower circuits can therefore be deferred to beyond the planning period Transmission System There are two single phase 110/33kV transformer banks at Kaikohe, one rated at 30MVA and the other at 50MVA. Even at current loads, support from Ngawha generation is required should either of these transformer banks be out of service at times of peak demand. The single circuit 110kV transmission line between Kaikohe and Kaitaia has a winter rating of 68MVA, which is sufficient to supply the foreseeable Kaitaia load. Therefore, the existing constraint between Kaikohe and Kaitaia is one of security rather than capacity. There are two single phase 110/33kV transformer banks at Kaitaia, each rated at 22MVA. As the capacity is insufficient to provide N-1 security, in the event of failure of a transformer unit, supply might have to be rationed until a replacement unit (provided by Transpower in the short term) is transported to site and installed. Condition assessment indicates that both transformer banks have limited remaining life, replacement with new 40/60MVA units is planned for FYE The condition of the 33kV circuit breakers and outdoor switchyards at both substations, particularly Kaikohe, is a concern and these assets raise both reliability and safety issues. Outdoor 33kV switchyards are no longer considered good industry practice and outdoor-indoor conversions are planned at Kaikohe in FYE 2014 and Kaitaia in FYE A further issue is low 110kV voltage at Kaikohe, which can be a concern when Ngawha generation is not operating. This is primarily a Transpower problem, which should be alleviated with the commissioning of a new STATCOM at Marsden and the commissioning of a third 220kV circuit through the Auckland isthmus in Sub-transmission system A geographic diagram of Top Energy s 33kV sub-transmission network is shown in Figure 24. Figure 25 overleaf shows Top Energy s zone substation transformers. Top Energy generally purchases transformers that can be upgraded by the addition of cooling systems to suit increasing load growth. Historically, Top Energy has standardised on an 11.5/23MVA design for its larger load substations, to allow the relocation of transformers in case of an emergency if a single unit should fail. However, the tap changer range in some of the zone transformers limits the ability to maintain acceptable voltage levels. To allow transformer maintenance and to provide backup to locations where only a single 33/11kV transformer is installed, Top Energy has a 7.5 MVA mobile transformer unit. ASSET DESCRIPTION 43

46 ASSET DESCRIPTION SUBSTATION Kaikohe Kawakawa Moerewa Waipapa Omanaia Haruru UNIT NOMINAL ONAN/ ONAF OR OFAF MVA RATINGS WITH EXISTING COOLING Southern GXP PRESENT MAXIMUM MVA RATING T1 11.5/23 MVA ONAN/OFAF (Has pumps but no fans) T2 11.5/23 MVA ONAN/OFAF (Has pumps but no fans) T1 5 MVA ONAN (Has no pumps or fans) 5.00 T2 5 MVA ONAN (Has no pumps or fans) 5.00 T1 11.5/23 MVA ONAN/OFAF (Has pumps but no fans) MOB 5/7.5 MVA ONAN/ONAF (Has no pumps but fans are fitted) 7.50 T1 11.5/23 MVA ONAN/OFAF (Has both pumps and fans) T2 11.5/23 MVA ONAN/OFAF (Has both pumps and fans) T1-1 R MVA ONAN (Has no pumps or fans) T1-2 Y MVA ONAN (Has no pumps or fans) T1-3 B MVA ONAN (Has no pumps or fans) 2.75 T1 11.5/23 MVA ONAN/OFAF (Has pumps and one fan) T2 11.5/23 MVA ONAN/OFAF (Has pumps and one fan) Mt Pokaka T1 3/5 MVA ONAF (Has no fans) 3.00 Okahu Rd Taipa Northern GXP T MVA ONAN (Has no pumps or fans) T MVA ONAN (Has no pumps or fans) T1 5/6.25 MVA ONAN/OFAF (Has no pumps, but fans are fitted Pukenui T1 5/6.25 MVA ONAN/OFAF (Has no pumps or fans) 5.00 NPL 6.25 T1 11.5/23 MVA ONAN/OFAF (Has both pumps and fans) T2 11.5/23 MVA ONAN/OFAF (Has both pumps and fans) Figure 25: Present Zone Substation Transformers Figure 26 shows the transformer capacities together with the firm (N-1) capacity and the present transfer capacity (within 3 hours). The transfer capacity is the load that can be transferred to other substations in the event of a fault by reconfiguring the 11kV distribution network. It is important to note that the security rating refers to the sub-transmission network only, ie there is not N-1 to the northern area, as there is only one incoming 110kV circuit. As can be seen from the Figure, six of the ten zone substations are outside of the N-1 threshold. In addition, all of the substations operate in an open bus position, due to transformer protection constraints. This means that, even where sufficient capacity exists to meet the N-1 criterion, in the event of a sub transmission fault there will be a loss of supply until the network is reconfigured (generally through remote control from the Kaikohe control room) to utilise the available spare capacity. 44

47 ASSET DESCRIPTION SUBSTATION UNIT PRESENT RATING (MVA) SUBSTATION PRESENT CAPACITY (MVA) Southern Area Firm (N-1) 11kV feeder Switched Capacity Year Substation N-1 Exceeded Kaikohe T >FYE 2022 T Kawakawa T FYE T Moerewa T Current Waipapa T Current T (voltage constraint) Omanaia T Current Haruru T >FYE 2022 T Mt Pokaka T >FYE 2022 Northern Area Firm (N-1) 11kV feeder Switched Capacity Year Substation N-1 Exceeded Okahu T >FYE 2022 T Taipa T Current Pukenui T Current NPL T >FYE 2022 T Note 1: The current load exceeds the capacity of a single transformer but the switched 11 kv transfer capacity is sufficient to allow supply to all consumers to be restored before the mobile transformer is relocated. Note 2: Diesel generation. Figure 26: Present Zone Substation Transfer/Switching Capabilities Distribution system The Top Energy distribution system consists of 47 predominantly overhead line rural feeders, which supply 5,958 transformers. Figure 28 through Figure 38 show the distribution system for each of the Company s zone substations. The percentages of underground to overhead line are as follows: Sub-transmission - overhead 99%, underground 1% Distribution - overhead 94%, underground 6% Low Voltage - overhead 27%, underground 73% Due to the rural nature of the network, the majority of distribution substations are overhead in construction. 45

48 ASSET DESCRIPTION There are limited inter-connections available between substations and transformers at LV level, except in the urban areas of Kaikohe, Kaitaia, Kerikeri, Russell and Paihia. For more than 30 years, Top Energy has required new LV developments and subdivisions to be underground, which has resulted in a high percentage of underground distribution at LV level and a corresponding low level of LV faults. TEN s preferred LV connection arrangement is via looping between network pillars. This allows for the rapid identification and sectionalisation of the system in the event of localised network faults. Distribution transformers follow the ISO standard sizing. Pole mounting of transformers is limited to 100kVA for seismic considerations. Transformers may be 1, 2 or 3 phase according to customer or load requirement, or of the SWER type. Pad (berm) mounted transformers are steel cabinet enclosed units and may include switch units (total pad type), depending on the application. Figure 27: Transformer size kva Number Pole Mounts Number of Pad Mounts Under , , Distribution Transformer Population The geographic diagrams below show the coverage of the distribution feeders supplied from each of Top Energy s zone substations. Not shown: four NPL feeders supplying the Juken Nissho tri-board mill and one Mt Pokaka feeder supplying the Mt Pokaka Timber Products mill. 46

49 ASSET DESCRIPTION Figure 28: Geographic diagram of the Pukenui zone substation Figure 29: Geographic diagram of the Taipa zone substation 47

50 ASSET DESCRIPTION Figure 30: Geographic diagram of the NPL zone substation Figure 31: Geographic diagram of the 33kV Okahu Road zone substation 48

51 ASSET DESCRIPTION Figure 32: Geographic diagram of the Kaikohe zone substation Figure 33: Geographic diagram of the Waipapa zone substation 49

52 ASSET DESCRIPTION Figure 34: Geographic diagram of the Mt Pokaka zone substation Figure 35: Geographic diagram of the Haruru zone substation 50

53 ASSET DESCRIPTION Figure 36: Geographic diagram of the Kawakawa zone substation Figure 37: Geographic diagram of the Omanaia zone substation 51

54 ASSET DESCRIPTION Figure 38: Geographic diagram of the Moerewa zone substation Over 35% of Top Energy s lines were originally built using subsidies provided by the Rural Electrical Reticulation Council (RERC) to assist with post-war farming productivity growth in remote areas and to provide an electricity supply to consumers in sparsely populated rural areas, which would have otherwise been uneconomic to service. Many of these lines are now reaching the stage where extensive rebuilding and refurbishment is required, to the extent that continuing to supply many sparsely populated rural areas is not economic. However, Top Energy is obligated by Section 105(2) of the Electricity Industry Act 2010 to continue to provide a supply to consumers supplied from existing lines. The Electricity Networks Association (ENA) created a working party to review the implications of this obligation, particularly within distribution companies that include a large rural network component. To assist this review, in April 2009, Top Energy engaged Intergraph to create a trace within its GIS system to identify uneconomic lines using data based on the Ministry of Economic Development (MED) suggested test scenarios. This trace stepped through each piece of equipment within the GIS, feeder-by-feeder and identified where uneconomic lines begun. The start points were individually recorded and each of these start points became the beginning point of a further trace, which in turn identified all downstream equipment, therefore summing the length of uneconomic conductors. The results revealed that 32% of Top Energy lines are currently uneconomic, based on MED criteria. However, these lines feed only 8% of Top Energy s consumer base. The high proportion of uneconomic lines in Top Energy s supply area is a continuing burden on all Top Energy consumers Secondary assets Protection The company uses a mixture of protective devices on its network including: electromechanical relays, numerical relays, integrated protective devices such as pole top reclosers and sectionalisers, indoor and outdoor circuit breakers with either local or remote control functionality. 52

55 ASSET DESCRIPTION These devices are used to detect and isolate a fault as quickly as possible to ensure that damage is minimised. Low fault levels affect the reliability of protection, particularly where traditional electromechanical protection relays are used. Existing protection limitations mean that the sub transmission network is currently operated in a radial configuration, making interrupted N-1 security impossible. Top Energy has commenced a programme to progressively replace the electromechanical protection relays in its zone substations in order to improve the detection and discrimination of faults and to permit the parallel operation of sub transmission assets SCADA and communications TEN s system control and data acquisition systems (SCADA) operate out of TEN s Control Room in Kaikohe. The Company uses ipower SCADA systems to operate the electricity network. The ipower SCADA system communicates with various relays and integrated protective devices either using Abbey base station or by directly communicating to the devices using the various communication drivers available within the system. The company uses multiple communication protocols over its own VHF network or the leased UHF broadband network. The existing data communications system is nearing the end of its useful life and does not provide for new requirements, such as protection signalling. A modern system, utilising fibre optic cable and digital microwave links, will be progressively installed over the period of this plan and is described further in Section Load control system TEN owns and operates static ripple control plants via its SCADA system and injection is made at 317Hz onto its 33kV sub-transmission system. The plants are located at TEN s Kaikohe and Okahu Road substations, with a standby plant at Waipapa substation. The load management plants are used to control demand by allowing the organisation to control a range of load types to actively manage its peak transmission charges and to potentially defer capital investment on the network. The large number of receivers installed in the field, at the point where the controllable load is connected, are owned by energy retailers, not Top Energy. 3.2 Asset Details by Category In accordance with the Commerce Commission s Electricity Distribution Information Disclosure Requirements 2008, Top Energy discloses that its system fixed assets are valued at $143,974,000 as at 31 March 2011, an increase of $11,721,000 since 31 March This total does not include transmission assets that Top Energy will acquire from Transpower on 1 April 2012, valued at around $7 million. This increase in asset value is derived as follows: $000 Asset Value at 31 March ,253 Add: Addition of new assets 11,362 Indexed inflation adjustment 5,907 Less Depreciation 5,548 Asset value at 31 March ,974 Figure 39: Value of System Fixed Assets 53

56 Length (km) ASSET DESCRIPTION The different assets that make up Top Energy s system fixed asset base are discussed in the sections below Overhead conductors Overhead conductors are split into three categories, sub-transmission (33kV), distribution (22kV & 11kV) and low voltage (400V). The types of overhead conductor known to be installed on Top Energy s Network includes a mixture of imperial and metric sized conductors of the following types: Aluminium Conductor Steel Reinforced ACSR, Hard Drawn All Aluminium Conductors AAC, Bare Hard Drawn Copper, PVC Insulated Copper (LV), Galvanised Steel Wire. Top Energy s network is in close proximity to the sea at certain locations, therefore there is high content of salt in the atmosphere that causes corrosion of ACSR conductor. To overcome this, TEN now uses all aluminium alloy conductor (AAAC) on new transmission and sub-transmission lines, except for very long spans that require the additional strength of ACSR Sub-transmission The figure below shows the age profile of sub-transmission overhead conductors Age Profile of sub-transmission overhead conductors Total 0 Age (years) Figure 40: Age profile of sub-transmission overhead conductors There is a total of 266km circuit length of sub-transmission overhead conductor, which is generally in an acceptable condition Distribution The figure overleaf shows the age profile of distribution overhead conductors. There is a total of 2,560km circuit length of distribution overhead conductor. The condition of main feeder conductors is generally acceptable, however older conductor used for some SWER lines is reaching end of life and will require replacement during the planning period. 54

57 Length(km) Length (km) ASSET DESCRIPTION 150 Age profile of distribution overhead conductors Total 0 Age (years) Figure 41: Age profile of distribution overhead conductors Low Voltage The figure below shows the age profile of low voltage overhead conductors Age profile of low voltage overhead conductors Age (years) Total Figure 42: Age profile of low voltage overhead conductors There is a total of 228km circuit length of low voltage overhead conductor, which is of average condition. The main problem is conductor clashing caused by vegetation. This is being targeted through the year as part of the vegetation strategy described in Section 6. Replacement options for the 228km of average condition conductor will be determined on a case-by-case basis, including the use of LV ABC or undergrounding Poles and Structures Poles and structures are split into three categories: sub-transmission, distribution and low voltage. Top Energy has used a range of poles and structures for the construction of its network. Four types of poles and structures have been used: hardwood, softwood, steel and concrete. Top Energy was an early adopter of concrete poles and hence the proportion of wooden poles on the network is not as high as on some networks. Wooden poles are now being phased out. The pole assets for each voltage level are considered separately, a pole s voltage level is determined by the highest voltage supported by it. 55

58 Count of poles Count of poles ASSET DESCRIPTION The sub-transmission network has been built sporadically over the last 60 years and distribution poles have been mainly concrete, since the 1960s Sub-transmission The figure below shows the age profile of sub-transmission poles Age profile of sub-transmission poles Age (years) Total Figure 43: Age profile of sub-transmission poles There are a total of 2,889 sub-transmission poles. These are inspected annually and the majority are in good condition Distribution The figure below shows the age profile of distribution poles Age profile of distribution poles Age (years) Total Figure 44 Age profile of distribution poles There are a total of 31,104 distribution poles. Although Top Energy s distribution poles are generally in good condition, some work is required on aging SWER lines. The majority of the higher risk wooden poles lie within this category and it is planned that wooden poles will be replaced by pre-stressed concrete structures over the next 20 years Low Voltage The figure overleaf shows the age profile of low voltage poles. There are a total of 1,428 low voltage poles. TEN has built very little LV overhead line since 1986 and this is reflected in the graph, with only 222 poles less than 20 years old, many of these are replacements. These assets will continue to be inspected for condition on a regular basis and replaced as necessary. 56

59 Length(km) Count of poles ASSET DESCRIPTION 200 Age profile of low voltage poles Total 0 Age (years) Figure 45 Age profile of low voltage poles Underground Cables Similar to overhead lines, underground cables are split into three main categories, sub-transmission, distribution and low voltage. Cables used at 11kV, 22kV and 33kV are metric sized single or three core cables that are either Paper Insulated Cables (PILC) or Cross-Linked Polyethylene (XLPE) insulated. However at low voltage, Top Energy used imperial sized single core and metric 4 core PVC cables until Top Energy has now introduced the use of metric sized single and four core aluminium low voltage cables, which will replace the existing single core imperial range Sub-transmission Top Energy s only sub-transmission cable is 0.5km of 33kV Al XLPE cable (two circuits), near NPL substation. This cable was installed in 2000 and is in good condition Distribution The figure below shows the age profile of distribution underground cables Age profile of distribution underground cables Age (years) Total Figure 46: Age profile of distribution underground cables 57

60 Length(km) ASSET DESCRIPTION There is a total of 168km of distribution underground cable, which is generally in good condition with 81% of the in-service cable being less than 15 years old. Top Energy experiences, on average, one underground high voltage fault every 3 to 5 years, with the majority of these being joint failures or third-party damage. This is reflective of both the limited amount and young age of Top Energy s underground distribution system. On-going monitoring of system loadings and fault trends will continue through the planning period of the AMP Low Voltage The figure below shows the age profile of low voltage underground cables Age profile of low voltage underground cables. Age (years) Total Figure 47: Age profile of low voltage cables There is a total of 636km of low voltage underground cable, which is of average condition. On-going monitoring will continue to identify any developing fault trends Submarine Cables There are two submarine cables presently feeding the Russell area. The first cable is laid across the Waikare Inlet and is a single circuit, three core 70mm 2 copper cable, around 1.5km long and was livened in It has been through 33 years of its nominal 70 years economic life. The second cable is across the Veronica Channel between Opua and Okiato Point and is a single circuit three core 150mm 2, 11kV copper cable livened in Streetlight Cables Street light cable (222km) has not been included in the above. In general, this cable has ample life remaining and should not require significant maintenance during the planning period. A strategy for dealing with street lighting in the longer-term will be developed in conjunction with the light owners, before maintenance becomes a significant issue Distribution Transformer and SWER Transformers The age profiles of Top Energy s in-service distribution and SWER isolating transformers are depicted in the figures overleaf. There are a total of 5,958 distribution transformers of various capacities, with 65% of the equipment being less than 20 years old. In general, Top Energy s transformer population is of average condition. Top Energy considers the most appropriate strategy for the management of smaller distribution transformers to be one of run to failure. However, transformers that are deemed upon inspection to 58

61 Count of SWER isolating transformers Count of distribution transformers ASSET DESCRIPTION pose a risk to persons, safety, environment or property are replaced. Transformers are inspected on a biannual basis Age profile of distribution transformers Age (years) Total Figure 48: Age profile of distribution transformers (all capacities) Age profile of SWER isolating transformers Total Age (years) Figure 49: Age profile of SWER isolating transformers There are a total of 75 SWER isolating transformers, which are of average age and condition. SWER transformers are managed on an individual basis, with replacement being driven large by the need to increase the transformer capacity at a particular location. This has led to some acceleration in the rate of replacement in recent years, with 40% of the equipment being five years old or less Reclosers The figure overleaf shows the age profile of reclosers on Top Energy s Network. There are a total of 3 sub-transmission and 111 distribution voltage reclosers on the network, 36 of which (including all the sub-transmission units) were installed as part the network automation project that commenced in The general condition of reclosers is good and annual condition inspection is carried out to identify any maintenance or replacement requirements. 59

62 Count of regulators Count of reclosers ASSET DESCRIPTION Age profile of Reclosers Distribution Sub-transmission Age (years) Figure 50: Age profile of reclosers Voltage Regulators The figure below shows the age profile of the voltage regulators on Top Energy s network. Age Profile of Regulators Age (years) Total Figure 51 Age profile of regulators There are a total of 22 voltage regulators on Top Energy s Network. These are all less than ten years old and are in good condition. An annual condition inspection is carried out to identify maintenance requirements Ring Main Units (RMU) The figure overleaf shows the age profile of RMUs on Top Energy s Network. There are a total of 508 RMUs on Top Energy s Network. The condition of the older units is considered fair. A partial discharge issue has been discovered on the cable terminations of a small percentage of the population. Annual condition inspection together with partial discharge testing is carried out to identify replacement requirements. The RMUs are predominantly ABB SDAF units. These are now being phased out and new and replacement installations will be non-oil filled units. 60

63 Count of sectionalisers Count of Ring Main Units ASSET DESCRIPTION Age profile of ring main units Total 0 Age(years) Figure 52: Age profile of ring main units Sectionalisers The figure below shows the age profile of sectionalisers on Top Energy s Network. Age profile of sectionalisers Age (years) Total Figure 53 Age profile of sectionalisers There are a total of 255 sectionalisers on Top Energy s Network, most of which are configured as remote controlled switches. Sectionalisers are a relatively new asset on the network and have been installed as part of the network automation project, allowing field switching of the network to take place remotely from the control room. This reduces the duration of supply interruptions by speeding up the location of faults and reconfiguration of the network, to restore supply to consumers not directly affected. Replacement of the three remaining older units will be undertaken as part of the routine maintenance schedule. 61

64 Count of Capacitors ASSET DESCRIPTION Capacitors The figure below shows the age profile of capacitors on Top Energy s Network Age profile of capacitors 2 Total Age (years) Figure 54 Age profile of capacitors There are a total of 21 capacitors on Top Energy s Network and they are all of average-to-fair condition. Annual condition inspection is carried out to identify any replacement requirements Zone Substation Equipment Power Transformers & Tap-changers The Figure below shows the details of power transformers located at Top Energy s zone substations. PRESENT SUBSTATION UNIT DESIGN RATING MVA Southern PRESENT RATING MVA AGE 1 Kaikohe T1 11.5/ Kaikohe T2 11.5/ Kawakawa T Kawakawa T Moerewa T1 11.5/ Waipapa T1 11.5/ Waipapa T2 11.5/ Omanaia T1-1 R Omanaia T1-2 Y Omanaia T1-3 B Haruru T1 11.5/

65 ASSET DESCRIPTION Haruru T2 11.5/ Mt Pokaka T1 3/5 3 2 Northern Okahu Rd T Okahu Rd T Taipa T1 5/ Pukenui T1 5/ NPL T1 11.5/ NPL T2 11.5/ Mobile Substation Mobile Substation T1 5/ Note 1: As at 31 March 2012 Figure 55: Power transformers installed at zone substations The life expectancy of a power transformer is 60 years, where the transformer has not been heavily loaded and appropriate maintenance practices are in place, this applies to Top Energy s fleet. The actual age at which a power transformer will be replaced will depend on its condition, loading, history and design, Top Energy expects that most of its transformers will last their full expected life. Furan oil analysis is used as a non-invasive indication of the degree of polymerisation (DP) of the transformer insulation. The remaining life of a transformer is assessed on the basis of actual DP tests, which are undertaken if a major overhaul involving de-tanking at a transformer workshop is required. The DP at start of a transformer s life is about 1,200, and at end of life around Additional indications of cellulose degradation are levels of carbon monoxide (CO), carbon dioxide (CO 2 ) and the ratio of the two. The DPs of all power transformers were ascertained over , when paper samples of all power transformers were taken and analysed. The DPs were in two groups: most were between 695 and 1,300, indicating plenty of life left in the cellulose, whereas the three single phase Metropolitan Vickers units at Omanaia, which are now 58 years old, are closer to end of life at These transformers will be replaced by the existing Taipa unit in FYE In the meantime the mobile transformer unit is available as a backup should this be required Circuit breakers a) Sub-transmission circuit breakers The figure below shows the quantities and age profile of Top Energy s sub-transmission circuit breakers installed within its zone substations. In addition there are four new circuit breakers currently being installed in the field, outside zone substations. These will be operated from the control room and will provide greater flexibility to reconfigure the network to meet operating requirements. 63

66 Count of 11kV circuit breakers Count ASSET DESCRIPTION Age profile of sub-transmission circuit breakers Age (years) Total Figure 56 Age profile of sub-transmission circuit breakers Top Energy has a relatively small number of sub transmission circuit breakers and, as a result, there is a concentration of types. There are 10 English Electric OKW3 minimum oil outdoor 33kV CBs, all but two are more than 35 years old. Minimum oil CBs are noted internationally as having a major risk of failure if the maintenance programme is not rigorously followed. The first instance requiring replacement occurred in 2005 and a second replacement occurred in Extension of service beyond their standard lives is expected to be achieved through regular maintenance and testing practices, to manage the risk of a failure. Until replacement of these circuit breakers occurs, Top Energy will apply a strict maintenance regime on a 12 monthly cycle. Circuit breakers that are 10 years old or less all have vacuum interrupters. b) Distribution Circuit Breakers The figure below shows the age profile of 11kV distribution voltage circuit breakers presently in service on the Top Energy system Age profile of 11kV circuit breakers 10 Total Age (years) Figure 57: Age profile of distribution voltage circuit breakers 64

67 ASSET DESCRIPTION The condition of these 70 items is considered sound, with thorough testing and condition based maintenance in place. No age-based replacements are planned in the planning period, however some oil breakers may be relocated to a lesser duty site and thereby reduce maintenance costs. While the low fault levels in the Top Energy network increase the complexity of protection design, they do have the advantage of increasing the expected life of circuit breakers. The Figure below shows the type and location of 11kV circuit breakers. SUBSTATION INTERRUPTER TECHNOLOGY INSTALLATION DATE Indoor Breakers Haruru Vacuum 1998 and 1993 Kaikohe Oil 1970 and 1975 Kawakawa Oil 1962 NPL Vacuum 1987 and 2000 Okahu Road Oil 1978 Taipa Oil 1978 Outdoor Breakers Moerewa Vacuum 1975 Omanaia Oil 1984 Pukenui Oil Reclosers 1975 Waipapa Oil and Vacuum Reclosers 1965 and 1975 Mt Pokaka SF Figure 58: Type and location of 11kV circuit breakers Zone Substation Structures Top Energy s outdoor structures, like overhead lines, have a long life span. Their condition is monitored visually and with the use of thermal imaging. Because of the critical nature of the air insulated switch items within substations, these are individually checked for correct operation every two years and maintained if necessary Zone Substation DC Systems The age profile batteries and charger systems are shown in the figure overleaf. Top Energy inspects and tests the battery banks monthly and replaces the whole bank at the end of its economic life. 65

68 No of Units ASSET DESCRIPTION Batteries Chargers Age (years) Figure 59 Age profile of batteries and chargers Zone Substation Protection At present, Top Energy has a variety of relay classes: electromechanical, solid state and modern microprocessor relays. Their ages generally correspond to the age of the substation concerned. The exceptions are Okahu Road and NPL, which have had replacement relays installed since An upgrade of all zone substation protection relays has commenced, moving to a numerical type with improved discrimination and capable of data logging. The low fault levels in Top Energy s supply area complicate protection design and, as a result the sub-transmission network is currently in a radial configuration to mitigate the potential for, and consequences of, mal-operation. Unfortunately this means that all sub-transmission faults will cause a supply interruption, even where capacity is sufficient to provide N-1 supply security. The new protection relays will allow subtransmission lines and zone substation transformers to be operated in parallel, meaning that most faults on the sub-transmission system should not result in a supply interruption. Over time, this should contribute to an improvement in supply reliability. The new relays will also log load and fault data, allowing for better network analysis and in turn service delivery. This will also assist in tariff and loss calculations, and the allocation of costs. Haruru is the first substation where the new relays will be installed, installation of new protection schemes at this substation is currently in progress. Installation of these relays at other zone substations will follow progressively. 66

69 Count of pillars ASSET DESCRIPTION Zone Substation Grounds and Buildings Top Energy s Substation Buildings are listed in the Figure below. SUBSTATION NAME CONSTRUCTED Kaikohe 1971 Kawakawa 1961 Moerewa 1970 Waipapa 1965 Omanaia 1983 Haruru Falls 1988 Mt Pokaka 2010 Okahu Road 1979 Taipa 1985 Pukenui 1976 NPL 1987 Figure 60: Age profile of substation buildings The buildings are all considered to be in fair condition, although maintenance on zone substation buildings (i.e. roof repairs) may be necessary within the planning period. Regular building inspections and maintenance programmes ensure their on-going utility Customer Service Pillars Customer service pillars contain the fuses to protect/disconnect individual properties from the LV supply network. The figure below depicts the age profile of customer service pillars currently recorded as being in service on the Top Energy system. There are a total of 11,602 installed on the network. Customer service pillars are generally allowed to run to failure, although pillars that are found to be damaged during routine asset inspections are repaired or replaced. 800 Age profile of customer service pillars Total 0 Age (years) Figure 61 Age profile of customer service pillars 67

70 SCADA and Communications Top Energy s existing SCADA system architecture was rolled out in 2004 with an upgrade of communications and protection at the NPL Substation, and installation of new software in the control centre. The architecture consists of distributed data collection and operation via an Ethernet wide area network (WAN). Communication usually is direct with protection and measurement transducers in zone substations and HV switching device locations. The systems comprises of: microwave link equipment operating at speeds from 256kB up to 10MB from each control or monitoring point to either Maungataniwha (Northern GXP network) or Mt. Hikurangi (Southern GXP network), a leased 2MB link from Maungataniwha to Mt Hikurangi a front end in the control centre comprising of an ipower HMI system and backup servers at an alternate location, connected via the Ethernet WAN. The figure below shows the location of communications repeater sites. The existing communications system is reaching the end of its useful life and is not capable of providing some functions, such as protection signalling, which the network now requires. It will be progressively replaced by a modern system using fibre-optic cable and digital microwave links as part of the network development plan. This is discussed further in Section 5. ASSET DESCRIPTION Figure 62 Repeater tower sites 68

71 ASSET DESCRIPTION Top Energy is now using the SCADA system to monitor and control zone substation equipment, and to remotely control sectionalisers and reclosers located on the field. There are currently approximately 150 field located control and monitoring points Load Control Plant Top Energy has three Zellweger decabit type injection plants operating at 317Hz connected to its northern and southern networks. The northern plant is rated at 33kV with 30MVA capacity, commissioned in 1991 and the southern plant is rated at 33kV with 80MVA capacity, commissioned in There is also a southern standby plant at Waipapa rated at 33kV with 30MVA capacity, commissioned in There are 100 channels available for load control and Top Energy presently uses 45 of these Generation Top Energy installed two 2.5MVA diesel generator sets at Taipa substation in This generation is used as a backup supply in the event of a loss of the incoming sub-transmission line or substation transformer. 3.3 Justification for Assets TEN s network assets are used to accept electricity from Transpower s grid exit point at Kaikohe and from the Ngawha geothermal generation plant, and to distribute the electricity to consumers in its supply area with the level quality and reliability that meets their expectations. While the existing assets have historically met consumer requirements, the demand for electricity and consumers expectations are now exceeding the capacity of the existing asset base, as noted in Section 2.4. Top Energy is implementing a new network development plan (described in Section 5), which will put an augmented transmission and sub-transmission infrastructure in place to meet the expectations of electricity users in the Far North for the next 20 years and beyond. The existing asset base forms the platform from which this higher capacity network will be developed. The current network is substantially radial in nature and includes a 110kV transmission line, 33kV subtransmission lines, 22/11kV distribution lines and a 415/240V low voltage network. The different voltage networks are interconnected through substations, which transform the electricity from a higher to a lower voltage. The high voltage distribution network comprises primarily three wire and two wire overhead and underground lines, but also includes many single wire earth return (SWER) lines of varying lengths, to serve remote and sparsely populated rural areas. The low voltage network comprises two, three and four wire lines, which are largely underground. The two transmission substations receive electricity from the Transpower grid and inject it into Top Energy s sub-transmission network, which supplies the zone substations. The 33/11kV zone substations are configured with either dual transformer banks or a single transformer bank depending upon the security and load requirements in the area. Top Energy believes this asset base is no longer adequate to provide acceptable supply reliability to consumers and comply with statutory requirements related to delivery voltages. Distribution feeders generally operate at 11kV and are long for this voltage. The identification of surplus or over-capacity assets was considered in the optimisation process undertaken in 2004 for asset valuation purposes and then updated in This analysis (discussed below) identified a small number of assets for optimisation, the majority being for capacity reasons rather than being superfluous. Load growth since 2004 has resulted in some optimised asset capacity, from the 2004 valuation being reabsorbed into the network following the 2011 review. Asset capacity that remains optimised out of the asset base is assigned zero value for regulatory purposes and is therefore not taken into account in regulatory financial and tariff analysis. 69

72 3.3.1 Transmission System The 110kV transmission substations at Kaikohe and Kaitaia are approximately 80km apart with a range of uninhabited hills in between. The southern and northern area distribution networks are interconnected at 11kV at only one remote location and Top Energy s northern and southern area networks could not be practically interconnected using 33kV sub-transmission lines. Both substations have dual 110/33kV transformers to allow the transformers to be maintained during off peak periods without loss of supply. The transmission system is supplied from Mangatapere using a double circuit 110kV line up to the Kaikohe substation, power is injected into Top Energy s transmission system at the two incoming circuit breakers at Kaikohe. The Kaitaia transmission substation is, in turn, supplied using a single circuit 110kV line from the Kaikohe substation. As the Kaitaia substation is supplied with a single circuit, it is not possible to maintain supply to consumers connected to the northern distribution network if this circuit is out of service for any reason. Ngawha generation also provides 25MW injection into the Top Energy sub-transmission network at 33kV. The Ngawha power station is situated approximately 7km from the Kaikohe GXP. The power station is connected to TEN using two single circuit 33kV lines. No optimisation of the transmission system is possible. ASSET DESCRIPTION Sub-transmission network After considering the forecast load, N-1 security and voltage drop conditions under both normal and contingent operation, no optimisation is possible for the sub-transmission network. As noted above Top Energy now believes the existing sub-transmission network is only marginally adequate to supply current loads with an acceptable level of reliability Northern Network Pukenui and Taipa substations are supplied using single circuit 33kV lines. The anticipated peak loads at the substations could not be supplied at 22/11kV voltage level due to the distances involved, the subsequent voltage drop and the projected load growth in the area. The two larger substations, Okahu and NPL, are supplied using a shared double circuit 33kV line. This provides N-1 security (apart from pole failure). Voltage drop under N-1 contingent operation and loss considerations under normal operation preclude a reduction in the conductor size of these lines Southern Network Waipapa substation is supplied using two dedicated 33kV lines. The forecast future load in the Waipapa substation area, voltage drop under N-1 contingent operation and the security requirement set out in this plan will exceed the capacity of the existing 33kV supply lines in the near future, precluding a reduction in the conductor size in the shorter term. Haruru, Kawakawa and Moerewa substations are all supplied using two shared 33kV lines and operate on a split bus basis, due to load and protection constraints. Considering the present peak load and the voltage drop on both the lines under those conditions, a reduction of the conductor size on these lines is not viable. Kaikohe substation is supplied using a single 33kV tie line from Kaikohe GXP. Omanaia Substation is supplied using a single 33kV line from Kaikohe GXP. This substation cannot be supplied at 22/11kV voltage level, due to the distance involved and subsequent voltage drop Zone Substations All zone substations in the network are separated by significant distances and, in general, by low density rural land. Top Energy also owns a 7.5MVA 33/11kV mobile substation that provides back up for planned substation maintenance at all single bank substations. There is some backup available for most zone 70

73 ASSET DESCRIPTION substations from adjacent substations via the distribution network, but this backup is severely limited due to voltage drop on the distribution feeders under contingent operations. There are three areas of zone substation optimisation on the Top Energy Network. Firstly, due to the closure of the dairy factory at Moerewa and a reduction in load at the freezing works, the capacity of the 11.5/23MVA transformer at Moerewa zone substation has been optimised to 5/10MVA. At Omanaia zone substation, there are three single phase transformer units with separate voltage regulators. This combination was optimised to a single three phase unit, with an internal on-load tap changer (OLTC). All other zone substation transformers are of appropriate size to supply present load under normal operating condition and most (but not all) substations meet the N-1 security criteria, as far as transformer size is concerned, given the forecast load increase for the planning period. The second area of potential zone substation optimisation is where Top Energy s standard design provided for extra switches at the time of construction. Where these switches are not required to provide N-1 contingent operation, they have been optimised out. Finally, the zone substations land and building have been adjusted to reflect an appropriate size. Single bank substation sites have been optimised to 2000m 2 and double bank substations to 3000m 2. The possibility of optimising indoor 11kV zone substation switchgear to outdoor was reviewed and ruled out on the basis that the cost of an outdoor switch, its associated isolators and their mounting structures, exceed the value of its indoor equivalent. In any case, installation of outdoor subtransmission and distribution voltage switchgear at zone substations is no longer considered good industry practice, because of safety and reliability concerns. There is no double bus bar arrangement or automatic fire fighting or fire detection systems installed in any of the zone substations. Transformer oil bunding facilities are installed in some of the zone substations. A programme is in place to install bunding for the rest of the zone substations during the planning period Distribution network Factors such as current rating, losses and voltage drop are considered in deciding whether distribution network conductors could be optimised to smaller size. Although Top Energy does not specify an N-1 criterion for feeders, due to the mainly rural nature of the network and therefore the impracticality of providing full back up, it does make use of feeder interconnections close to the substations to reduce the number of outages required for planned substation maintenance. This is standard industry practice. To achieve the security criteria set out in this AMP, the feeder current rating has to be adequate to carry its own load and that of any feeder it backs up. This criterion precluded optimisation of conductors on the distribution feeders. The next criterion for assessing whether a smaller conductor should be used is the relative cost of losses and capital. If the long term cost of losses exceeds the extra capital cost of the increased size of conductor, then a smaller conductor should not be used. The conductor comparisons carried out suggest that, for any feeder with more than 1MW of peak load, the cost of losses exceeds the capital cost of the increased size conductor. That also precluded the optimisation of conductors. The third criterion is the need to maintain voltage within acceptable levels. The chart below shows the load capacity for Top Energy s medium conductor (Bee 130mm 2 ) and its light conductor (Ferret 40mm 2 ) based on a 4% volt drop. 71

74 L o ad in M V A ASSET DESCRIPTION T ransm ision Capacity Volt Drop L en g th in km B ee F erret Figure 63 Conductor transmission capacity Vs distance The figure above shows that any feeder longer than around 5km, with more than 1MW of load evenly spread along its length under normal or back up conditions, should use a medium conductor, at least. The above criteria preclude optimisation of all feeders except Tau Block and Pokapu, supplied from Moerewa substation. Pokapu cannot sensibly be used to back up the AFFCo feeder, but has less than 1km of medium size conductor, therefore optimisation is not considered material. Tau Block is used to back up the remaining two feeders out of Moerewa substation in order to meet the reliability requirements of the industrial customer adjacent to the substation. Therefore, no optimisation of the distribution network is possible. This lack of optimisation is indicative of the relatively high loading on the distribution system and the very long feeder lengths that currently exist. This will be alleviated by the network development plan, which will increase the number of points at which electricity is injected into the distribution network. This in turn will reduce the load on many existing heavily-loaded feeders Distribution transformers The optimisation review undertaken in 2011 determined that the utilisation of distribution transformers is now above 30%, so the current distribution transformer capacity installed on the network is not excessive Low voltage network TEN provides no back up for LV circuits. Circuits are two, three or four wire and use medium size conductor. Reviews of current and past designs indicate that a larger conductor would be required if Top Energy was to provide back up of LV circuits, but voltage drop rather than capacity is the predominant constraint. Increasing the conductor size is not the optimal solution in general. New construction consists entirely of underground cables. This is a requirement of The Far North District Council for urban areas and no optimisation is possible. In rural areas, where customers service mains are not connected directly to a transformer, the extra cost of underground cables is met by means of capital contributions, no optimisation is possible. 72

75 3.3.7 Voltage control devices Voltage regulation is achieved at the zone substations using conventional on-load tap changers (OLTC), except at Omanaia. In addition, Top Energy has twenty two 11kV voltage regulators located within the distribution network, typically in pairs. One pair is situated at Omanaia zone substation and is subject to optimisation with the transformer. The others are on feeders over 30km long, where there is too much load at the end of the feeder to maintain statutory voltage without a regulator. TEN has a small number of fixed capacitor banks attached to the 11kV. These were placed to improve power factor and voltage quality on feeders. These banks are not included in the valuation as there is no category and their omission is immaterial. No optimisation is possible, apart from the optimisation at Omanaia substation, which is based on the use of a modern equivalent asset rather than capacity. ASSET DESCRIPTION Load control plant TEN uses Enermet (Zellweger) 33kV injection plant at Kaikohe and Kaitaia and a backup injection plant for the southern network at Waipapa. The lack of interconnection between the two GXPs prevents any further aggregation. No optimisation is possible SCADA equipment TEN uses SCADA to monitor and control its Zone Substations, GXPs and remote control equipment on the network. TEN has installed remote control equipment such as motorised switches, reclosers and circuit breakers at both sub-transmission and distribution voltage level, in order to improve reliability and to meet the security criteria set out in the AMP. With only 42 non-industrial distribution feeders and more than 2,500km of overhead HV line, the ability to reduce the time it takes to restore supply to parts of the feeder by remote control while locating the fault is necessary to bring customer service levels to acceptable standards. No optimisation is possible Spares The only critical spares held and included in the valuation are distribution transformers. The numbers and sizes are defined in a specific agreement with the TECS store in addition to the normal construction stocks. No optimisation is possible. 73

76 LEVEL OF SERVICE Section 4 Level of Service 4.1 Introduction Customer Orientated Service Levels Adopted customer service level Historic customer service levels delivered Strategies to improve the customer level of service Asset Performance and Efficiency Targets Loss ratio Cost Performance Justification for Service level Targets Customer Consultation telephone survey High user consultation Summary Justification for Asset Performance and Efficiency Targets Loss Ratio Operational Expenditure Ratio 88 74

77 LEVEL OF SERVICE 4 Level of Service 4.1 Introduction Top Energy distributed electricity to approximately 31,000 consumers during via approximately 3,900km of lines and cables of which 80% is overhead. This gives an average consumer density of 7.9 consumers per km. This groups Top Energy with a peer group of companies that includes MainPower, Eastland Network and Alpine Energy, these organisations also have significant areas of rural supply. Top Energy is one of the worst performing electricity distribution businesses in New Zealand in terms of supply reliability. During FYE 2011, on average, each customer experienced five outages and more than seven hours without electricity. This is the result of a complex mix of historical design, investment, ecological and climatic factors. It is now recognised that with suitable development and maintenance strategies and adequate funding, the effects of these factors on supply can largely be mitigated. The poor network reliability is, in some part, a consequence of the fringe location of the network and the resulting limitation of having only two transmission substations, when a more strategically located rural network of similar size would typically have many more. Further, the transmission substations are poorly located to serve the present load, since they were constructed during an era when the inland urban centres of Kaikohe and Kaitaia were the hub of both economic and population growth within the Far North region. Over the last ten years, there has been a steady decline in the growth of Kaikohe, whilst the region has seen significant expansion in Kerikeri, the Bay of Islands and the eastern coastal peninsulas. This drift in population away from the areas that the distribution network was originally designed to serve has driven a network development focus on incremental capacity increases to the existing distribution network rather than quality and performance improvement. The network is now characterised by long heavily loaded distribution feeders supplying pockets of fringe development with no major urban centre and inadequate sub-transmission support. This has resulted in some parts of the distribution network, supplying areas that were one considered fringe coastal communities, now operating at over 90% of capacity during peak periods. This heavy loading severely limits the ability to connect new customers and can make it difficult to restore supply to existing customers when a fault occurs. To address these legacy issues and to improve security of supply, Top Energy will invest approximately $150 million during the ten year period between 2012 and 2022 in what will be the single largest expansion in the history of the electricity network. It will acquire from Transpower and invest in improving the region s transmission assets, and construct a second 110 kv transmission circuit between Kaikohe and Kaitaia so that supply to consumers in the northern area will no longer depend on a single incoming transmission circuit. It will also expand and strengthen the 33kV subtransmission system in order to increase the number of bulk supply points at which power is injected into the older distribution network. The result of this expansion will be a significantly more secure and reliable network to support the future economic growth of the Far North. Bulk supply capacity is not the only focus of strategic investment, vegetation control and other initiatives designed to increase the distribution network s ability to withstand adverse weather events present a number of opportunities for significant performance improvement. In April 2009, Top Energy began a major reliability programme targeting the clearance of trees and vegetation near lines. It also installed equipment to reduce the number of faults caused by lightning and over 200 automated switches and re-closers in strategic locations, to limit the number of customers affected by many fault events. Overall, the result has been excellent. Network SAIDI reduced from 924 in FYE 2009 to 440 in This programme, assisted by relatively mild weather, reduced the average number of outages consumers experienced from more than ten in to less than five in As a company, Top Energy will continue to invest in technologies and strategies that offer the best mix of performance gains compared to the cost of implementation. 75

78 LEVEL OF SERVICE The work planned over the next decade will also have a significant impact on the human resource requirement at Top Energy, creating new job opportunities in the Top Energy area. A recruitment campaign for planners, project managers, electrical lines engineers and other staff is on-going. It is expected that more than 20 new permanent positions will arise from the investment in the electricity network operation over the planning period. Top Energy performs regular customer research to inform, educate and seek feedback from customers on what is an appropriate level of service. By assessing the company s performance and comparing it with specific target levels, Top Energy has identified those areas where improvement is required. Top Energy has also compared its performance with other similar Electrical Line Businesses (ELB) with the objective of achieving best practice. The results of customer research have been incorporated in the strategies discussed in this AMP and has guided development of the service target levels proposed within this chapter. 4.2 Customer Orientated Service Levels Measures and Targets The customer service targets included in this AMP are limited to industry performance measures used to monitor the reliability of the electrical network, as these are not discretionary. Further, Top Energy believes that these targets effectively measure the extent to which TEN is able to achieve its objective of supplying a reliable electricity supply to its customers. This also aligns with the view of the Commerce Commission, which also uses these indicators as the basis for setting a quality threshold to determine whether the electricity distribution businesses that it regulates are performing to an acceptable standard. The two indicators that Top Energy will use for the development of customer service targets are: SAIDI: System Average Interruption Duration Index. This is the accumulated total time that the average consumer connected to the network will be without supply in any measurement year as a result of faults and planned outages on the Top Energy sub-transmission and distribution network. The units are minutes, SAIFI: System Average Interruption Frequency Index. This is the total number of supply interruptions that the average consumer connected to the network will experience in a measurement year as a result of faults and planned outages on the Top Energy sub transmission and distribution network. The units are outages per customer per year. It should be noted that, while an individual consumer can only experience a whole number of outages, the target is set as a real number to allow for the effect of averaging. The service level targets set out in this AMP relate to the performance of the transmission, subtransmission and distribution networks. The inclusion of the transmission assets in the measure will decrease the measured reliability, because interruptions that have previously been excluded have been included in the measure. In measuring its performance against these targets, Top Energy will adopt the normalising approach that is now being taken by the Commerce Commission in measuring the reliability of supply provided by all the electricity distribution business that it regulates. Normalisation of the raw performance measure is designed to exclude the impact of events that are outside the reasonable control of the regulated entity. Top Energy believes that setting targets using normalised measures will provide a better indication of the success of its asset management strategies by limiting the extent to which events outside its control impact the measured performance. The normalisation process will have two effects. First, and as at present, interruptions due to an outage of the Transpower network will not be counted. TEN has no control over these outages and their impact on measured performance can be substantial. Second, the impact of interruptions occurring on major event days will be limited to an interruption envelope. The criteria for determining a major event day and the value of the interruption threshold will be determined from a statistical analysis of daily interruptions using the 76

79 LEVEL OF SERVICE methodology defined by the Commission. In practice, it has been found that the impact of interruptions over a year generally follows a statistical log-normal distribution, where interruptions occurring on only one or two major event days each year have a substantial impact on the measured performance. These major event days correspond to days of severe storm activity or days on which another event occurs that is outside the ability of TEN and TECS resources to control. The analysis methodology used by the Commission to normalise reliability performance for measurement purposes is based on IEEE standard , which has been developed for this purpose by the American Institute of Electrical and Electronic Engineers. The Commission s methodology, however, differs from the IEEE standard by requiring the actual impact of major event days to be replaced by an assessed threshold level, rather than allowing major event days to be ignored altogether. For Top Energy, the high level of annual SAIDI from FYE2007 to FYE2009 results in both a high annual boundary and high MED boundary values. The Transpower transmission assets that are to be transferred to Top Energy ownership on 1 st April 2012 are in a generally poor condition and are approaching end of life. Between FYE2005 to FYE2009 the transmission system has on average, experienced one or two major outage events every year. Transpower has to some extent mitigated unplanned system events by carrying out major planned maintenance outages and live line operations at our request, however the annual performance statistics remain quite poor. When the Class A and Class D Transpower SAIDI statistics specific to the Kaikohe and Kaitaia assets are included in the performance dataset for FYE2005 to FYE2009, the annual boundary and MED values change as below: Metric Existing Boundary Boundary with Transmission Change SAIDI SAIDI MED SAIFI SAIFI MED Figure 64 Quality Boundary Values In general, a major outage on the Kaikohe to Kaitaia line results in a single event of 220 SAIDI minutes. As any single day over the Major Event Day (MED) Boundary contributes a fixed to the total boundary regardless of the daily total, the large transmission outages are scaled back to this lower MED value. For example: A line outage on the Kaikohe to Kaitaia line, or the Kaitaia Substation in excess of 2 hours 36 minutes would result in an MED dispensation. A Substation outage for Kaikohe in excess of 1 hour 26 minutes would result in an MED dispensation. A total system outage in excess of 56 minutes would result in an MED dispensation. In reality, the boundary value at this level means that an MED classification would occur for most fault incidents on the Transmission assets and therefore any attributable SAIDI would rise in bands of minutes per fault (for faults on separate days). 77

80 LEVEL OF SERVICE Top Energy SAIDI Glideslope The FYE target for SAIDI performance is set at 342 to 239 SAIDI minutes. The original plan which prior to the transfer of the Transpower transmission assets, produced a SAIDI slope which achieves the Top Energy Statement of Corporate Intent target of 250 SAIDI minutes in 2016 and the Peer Group Mean of 200 SAIDI minutes in The strategic use of fixed Generation will result in a progressive Step Change in Network performance and the achievement of the Peer Group Mean in 2016, four years earlier than planned. Figure 65 Network Sub transmission and Distribution SAIDI Glideslope The adoption of the transmission assets from Transpower adds a significant level of risk to the system whilst the single circuit 110kV line to Kaitaia is the only source of transmission to the region. This risk will remain until the completion of the TE2020 project in FYE2016 and the closure of the 110kV ring between Kaikohe, Wiroa, Taipa and Kaitaia. A value of 60 SAIDI minutes has therefore been allocated to FYE2013, FYE2014 and FYE2015 to enable one planned outage on the 110kV Kaikohe to Kaitaia circuit to occur in each of those three years. The outages would facilitate: High risk 110kV remedial maintenance, reduce the likelihood of multiple unplanned outages prior to the completion of the 110kV ring. Enablement work for the connection of the TE2020 line in both Kaikohe and Kaitaia. Remedial maintenance work on 33kV zone substations and single circuit 33kV lines. Figure 66 Network SAIDI Glideslope with the addition of the Transmission Assets 78

81 LEVEL OF SERVICE This strategy, whilst increasing the annual SAIDI targets to 402 in FYE2013, 340 in FYE2014 and 318 in FYE2015, reduces the risk of an outage on the transmission system in FYE2016 and maintains the Statement of Corporate Intent target of 250 SAIDI minutes in FYE2016. Top Energy s normalised SAIDI and SAIFI targets for the planning period are shown in the figure below. SERVICE LEVEL TARGET 1 The regulatory benchmark applied over is 464. For , the new benchmark is Figure 67: Customer Service Level Targets FYE 2012 TARGET FYE 2013 TARGET FYE TARGET SAIDI (including transmission, but excluding Transpower) SAIFI ( Including Transmission, but excluding Transpower) The targets in the Figure above are averages. The exact levels of service experienced by an individual consumer will depend on the consumer s location on the network. These improved reliability targets over the regulatory threshold levels are possible due to the expected impact of Top Energy s vegetation management programme, and also the installation of remote controlled switches and reclosers on the network during the financial year to 31 March As shown in Figure 67, Top Energy is targeting even further improvements in reliability over the remainder of the planning period, which reflect the expected impact of the Network Development programme Historic customer service levels delivered The following figures show Top Energy s historical performance for both of these measures. The performances shown exclude the impact of Transpower outages YTD SAIDI Threshold AMP Target Figure 68: Historical SAIDI performance 79

82 LEVEL OF SERVICE SAIFI Threshold AMP Target YTD Figure 69: Historical SAIFI performance There has been a significant improvement in supply reliability between 2010 and 2012, largely as a result of Top Energy s investment in reliability improvement initiatives. The thresholds shown in the above figures are set by the Commerce Commission under its price quality regulatory regime and are based on historic performance. Under the price quality regime, Top Energy is subject to investigation by the Commission should the supply reliability be worse than the threshold level. There has been no threshold breach in the previous three years. The AMP target is separate from the threshold and is set internally by Top Energy. It is based on expected, rather than historic, performance. Top Energy has set itself challenging targets, reflecting its objective to significantly improve supply reliability and its planned investments in reliability improvement initiatives. While Top Energy met its SAIFI target in 2011, it missed the SAIDI target by 65 minutes. In spite of this, it was the company s best SAIDI performance since With a continuing focus on supply reliability, SAIDI is expected to improve in coming years and trend towards the internal targets Strategies to improve the customer level of service The poor 2008 SAIDI performance prompted a thorough review of interruption causes and maintenance practices in 2009, identifying the major causes. Following this analysis, Top Energy has developed strategies to mitigate the predominant causes of faults (as shown in Figure 70) and these strategies are expected to have a significant impact by Figure 70 also shows the progress that has been made towards meeting the 2015 targets. 80

83 LEVEL OF SERVICE INTERRUPTION CAUSE ACTUAL 2008 ACTUAL 2011 TARGET 2015 Vegetation Related 52% 10.43% 5% Lightning Related 21% 0.8% 2.5% Equipment Failure 9% 40.3% 5% Animals 4% 21.67% 2.5% Planned 9% 4.77% 50% 3rd Party 4% 1.18% 15% Transpower (unplanned) 1% - 20% Other % - Figure 70: Breakdown of line faults Internal targets have been set to: Reduce vegetation faults to < 30 Faults per year (currently 55) Reduce lightning faults to < 5 per year (currently 8) Reduce equipment failure faults to < 25 (currently 121) Monitor and target performance in line with the Identified industry peer group of companies A review of Figure 70 indicates that good progress has been made in reducing the number of unplanned interruptions due to external environmental causes, but the high number of equipment failure faults remains a significant concern. There is no quick fix for this issue, as equipment failures can occur anywhere on the network and are difficult to target in the short term. The high number of equipment failures is indicative of the overall condition of the existing asset base. This problem has historically been overshadowed by the high number of faults due to environmental causes but, now that these faults have been reduced by targeted maintenance strategies, it is exposed as a significant issue. In the short term the equipment failure problem is likely to limit the rate at which reliability can be improved beyond current levels. Over time, the problem should reduce as improved maintenance strategies have an impact and the network becomes more robust as a result of network development plan initiatives. Strategies that are being employed by Top Energy to improve levels of service include: Vegetation control. Vegetation related outages in 2008 to 2009 contributed 52% to the total SAIDI performance figure. Actively applying the NZ Tree Regulations provides an opportunity for Top Energy to make progress with what has been a difficult problem, because of the growth rate of vegetation locally, the high proportion of native trees and the low socio economic demography of the area. The regulations place the onus of responsibility with the tree owner, however there is initially a high expenditure by the network in the early years to enact the process. In March 2012, Top Energy completed a three year programme that invested around $3m pa on vegetation management to reduce the vegetation problem to a manageable level. Expenditure on vegetation management of the sub transmission and distribution network in is expected to be $2.2 million and will focus on the least reliable distribution feeders. the use of automatic switching devices and line fault indicators, (i.e. distribution automation), the remote control of switches, the use of live line work, and extensive data capture to obtain a better understanding of the asset base, so that Top Energy can improve the effectiveness of its condition-based replacement programme. 81

84 Loss Factor LEVEL OF SERVICE A factor that limits the basic achievable performance standards is the geographic spread of the network and the location of staff. It is necessary to have substantial depots from which teams or individuals work for logistical reasons and for backup during emergencies. Top Energy has two field staff depots, one at Puketona (equidistant from the urban centres of Kaikohe, Kerikeri and Paihia) and the second at Kaitaia. The travel time from these locations to remote areas significantly impacts fault response times. 4.3 Asset Performance and Efficiency Targets In order to ensure that its asset management strategies ensure effective utilisation of its asset base, Top Energy has developed targets to reflect its asset performance and efficiency. The targets for loss ratio and operational expenditure ratio are based on indicators that reflect the effectiveness the management of Top Energy s asset base for the benefit of electricity consumers in the Far North. Top Energy also considered including a target based on its capital expenditure ratio, but the implementation of the network development programme is likely to result in a volatile capital expenditure ratio over the planning period. This will limit the usefulness of this indicator as a measure of business performance Loss ratio Top Energy has suffered historically from a poor loss ratio, defined as the ratio of energy losses to the energy flowing into the network. Energy losses are measured as the difference between the energy flowing into the network and the energy sold out. Energy losses include both technical network losses due to the loss of energy flowing though the physical network and non-technical losses, due to other factors such as incorrect metering installations, meter errors and theft. In Top Energy s case, the relatively poor loss ratio is primarily driven by technical losses, which result from the high network loading and rural nature of the network. 10.0% 9.0% 8.0% 7.0% 6.0% 5.0% 4.0% 3.0% Loss Factor AMP Target 2.0% 1.0% 0.0% Year Ending 31 March Figure 71 Loss Ratios of Top Energy since FYE

85 LEVEL OF SERVICE SERVICE LEVEL TARGET FYE 2012 TARGET FYE 2013 TARGET FYE TARGET Loss Ratio 8% 8% 8% - 6.5% Figure 72: Loss Ratio Target Levels The selection of a target for the loss ratio reflects a wide range of issues. It is interesting to note that the traditional approach of justifying capital expenditure by making savings in the cost of energy no longer applies under the present market structure, where energy retailers, rather than network companies, are responsible for the cost of technical losses. Notwithstanding this, Top Energy considers loss ratio to be a valid performance measurement indicator, since minimization of losses benefits all parties in the energy supply chain, including consumers. Perhaps fortunately, often the same assets that need to be upgraded to meet voltage quality compliance are also significant contributors to losses. Top Energy s low customer density necessitates high total transformer capacity to provide individual transformers for rural customers, which in turn sets a higher level of standing losses than is typical for less rural networks. Non-technical losses are due to metering errors and electricity theft. Retailers are primarily responsible for metering, although both the retailer and the lines business share the cost of these losses. Top Energy is working proactively with both specialist external consultants and retailers to manage these issues. Historically, Top Energy has experienced a high loss ratio, running at approximately 10% from 1996 to In recent years, the loss ratio has been between 8% and 9%, this is still too high. Top Energy s short term loss target is 8% and it is targeting a value of 6.5% by 2022, which is more reflective of the average for rural networks in NZ. The long-term target demonstrates the expected performance improvements as a result of implementing the network development plan Cost Performance Ideally, any financial performance indicator should be directly measurable for performance against a specific target and independent of the annual effects of inflation. Top Energy has selected its operational expenditure ratio as an appropriate indicator of the financial effectiveness of its asset management efforts. The operational expenditure ratio is defined as the ratio of Top Energy s total operational expenditure during a measurement year to the replacement cost of Top Energy s system fixed assets at the end of the measurement year. It is a key financial performance indicator used by the Commerce Commission in its information disclosure regime, which was developed after extensive public consultation at a national level. Hence Top Energy s performance is directly comparable with the disclosed performance of its peer distribution utilities. Top Energy s recent operational expenditure ratio is shown in Figure 52. It is likely to rise to approximately 4.75% in FYE 2012, due to the impact of additional operational expenditure for the vegetation management programme and other maintenance initiatives. It was expected that, from FYE 2013 and beyond, the operational expenditure ratio would reduce significantly as a result of the completion of the three year vegetation management expenditure and an increased level of asset replacement. 83

86 Operational Expenditure Raio LEVEL OF SERVICE 4.60% 4.40% 4.20% 4.00% 3.80% 3.60% Operational Expenditure Ratio Target 3.40% 3.20% Year Ending 31 March Figure 73: Top Energy s Operational Expenditure Ratio since FYE 2008 The acquisition of the Transpower assets on 1 April 2012 is likely to impact Top Energy s operational expenditure ratio. Any appropriate adjustment to the ratio cannot be determined without 2 to 3 years experience of operational and maintenance issues around the assets required and will therefore be reviewed in future revisions of this plan. It has therefore been decided to retain the FYE 2012 target of 4.75% for FYE 2013 and to target a modest improvement in the operational expenditure ratio over the remaining years of the planning period. However these targets will need to be kept under review and may need to be reset over the next two or three years, as Top Energy gains experience in the operation and maintenance of its new 110kV transmission assets. SERVICE LEVEL TARGET FYE 2012 TARGET FYE 2013 TARGET FYE TARGET Operational Expenditure Ratio 4.75% 4.75% 4.75% % Figure 74: Financial Service Level Targets 4.4 Justification for Service Level Targets Top Energy s service level indicators are designed to measure the effectiveness of its asset management strategies, which have been developed to reflect the results of its consumer consultation process and other internal business drivers. An important economic consideration for Top Energy in setting service level targets is affordability of services, as the supply area covered by Top Energy is one of the poorest socio-economic areas in New Zealand. As discussed in Section 1.5, over 35% of Top Energy s lines were originally built using subsidies provided by the Rural Electrical Reticulation Council (RERC) to assist with post war farming productivity growth in remote areas and to provide an electricity supply to consumers in sparsely populated rural areas that would have otherwise been uneconomic to service. Currently 32% of Top Energy s lines, which supply just 8% of its consumer base, are considered uneconomic. 84

87 LEVEL OF SERVICE Accordingly, the service level targets must ultimately reflect the Top Energy Board s views on affordability, given this high proportion of uneconomic lines. This view was formed by the results of the customer consultation process described in Section below. It should be noted that the underlying service levels delivered by Top Energy to most of its customers over the year April 2009 March 2011 was a significant improvement on earlier years, as a result of several initiatives and targeted investment strategies aimed at reducing the number and duration of system outages. This is largely a response to a strong message from our consumers that current network performance levels are not acceptable. As demonstrated in this AMP, Top Energy continues to explore and implement suitable strategies for performance improvement Customer Consultation Top Energy has attempted to: advise its consumers about the price and quality trade-offs available to them in relation to the quality of supply provided, consult with consumers about the quality of supply that they require, with reference to the price of its distribution service, properly consider the views expressed by consumers during and after that consultation, and adequately take these views into account when making asset management decisions. Top Energy undertook a comprehensive consumer telephone survey and one-on-one discussions with major power users in 2009 to assist it formulate relevant asset management strategies, including the network development plan and to set appropriate performance targets. In Top Energy s experience, customer views do not normally change significantly over time, therefore, the results of this survey are considered to remain relevant during this planning period telephone survey An independent review was carried out of a random sample of 1,000 small use consumers. The breakdown by supply area and market segment is shown in the Figure below. MARKET SEGMENT BAY OF ISLANDS NORTH SOUTH SUB-TOTAL Rural commercial Rural residential Urban commercial Urban residential Not disclosed Total ,000 Figure 75: Customer survey The questionnaire (included as Appendix B) incorporated questions intended to inform, educate and elicit feedback useful to Top Energy in defining and setting target levels of service. The key conclusions drawn from the 2009 survey are: most customers can recall having a power cut within the last few weeks or months of the survey, 86% of customers consider Top Energy s supply reliability to be either acceptable or more than acceptable, 88% of customers recollections of changes in supply reliability are incorrect, 85

88 LEVEL OF SERVICE when told that supply reliability had actually declined, 54% of customers indicated that this was unacceptable (despite 86% of customers indicating that reliability was either acceptable or more than acceptable), 80% of customers wish to see an improvement in reliability (despite 86% of customers indicating that reliability was either acceptable or more than acceptable), expectations of prompt restoration appear high, with 64% of customers expecting power to be restored with 2 hours. The rural segment seems to be an exception with an even spread between less than 2 hours and 2 to 6 hours, expectations of continuity also appear high, with 25% of customers believing that the power should never go off, 62% of customers recall having a power cut of less than 1 minute, with only 10% considering this to be a major inconvenience, Customer preferences for fewer but longer outages, as opposed to more, but shorter outages, revealed a slight skew towards the latter. This seems at odds with the derived preferences for SAIFI, which indicate a preference for a low number of outages, Customers perceptions of an acceptable SAIDI level is approximately 346 minutes. This is significantly better than both Top Energy s historical performance and the regulatory threshold, 66% of customers would not be prepared to pay any more for a second 110kV line to the Kaitaia GXP, and Only 52% of those customers surveyed believe that a business setting up in the Far North should have access to a reliable electricity supply. The results of the 2009 consultation, and those undertaken in previous years, give Top Energy the following objectives: focus on improving service continuity and restoration as priorities, continue to improve the provision of restoration information in parallel with the fault restoration work, educate consumers to complete basic checks before they call and inform Top Energy of a fault, reduce flicker and surge where practical and where resources are available, and educate consumers on the causes of flicker and surge, and how hard it is to reduce flicker, Examining the customer responses to the questions relating to reliability of service and the length of outages, it is possible to draw direct conclusions as to customer expectations relating to SAIDI and SAIFI performance measures. Perceptions of acceptable SAIDI: Average customer perceptions of an acceptable SAIDI is about 346 minutes, which is better than what Top Energy has achieved in recent years and significantly better than the regulatory threshold. This is also in line with the five year SCI targets. MARKET SEGMENT BAY OF ISLANDS NORTH SOUTH Rural commercial Rural residential Urban commercial Urban residential Figure 76: Customer expectations SAIDI 86

89 LEVEL OF SERVICE The following conclusions are drawn from the Figure above in the Bay of Island area, rural and urban customers seem to have a similar perception of an acceptable SAIDI, in the northern area there is a gap between what rural commercial and urban commercial customers believe is an acceptable SAIDI, and expectations around rural reliability appear to be greater in the Bay of Islands than in the broader north and south areas. Perceptions of acceptable SAIFI: Average customer expectations of acceptable perceived SAIFI is 2.4, which is significantly better than Top Energy historical performance and the regulatory threshold. The SCI currently allows for a five year SAIFI target of 4.0 to 4.7. MARKET SEGMENT BAY OF ISLANDS NORTH SOUTH Rural commercial Rural residential Urban commercial Urban residential Figure 77: Customer expectations SAIFI The survey identified continuity of supply and prompt restoration of service to be the most important aspects of service, Top Energy interprets quality as synonymous with reliability (i.e. continuity and restoration). The customer service indicators adopted reflect this interpretation. The very high percentage of customers indicating that the current reliability of the network is acceptable and the majority expectation that power is restored within two hours, suggests that the recent SAIDI performance (which is at the top end of the Top Energy peer group and considerably higher than preferred) is acceptable. In spite of this, 80% of respondents indicated a desire to see reliability improved, Top Energy has adopted significantly improved forward service targets High user consultation In 2008, Top Energy engaged a specialist energy consultant to contact (by phone) the 12 largest consumers (the same consumer group Top Energy surveyed in 2006) and an additional 15 random commercial customers from the Top 100 commercial consumer group. Top Energy holds detailed discussions with each of its three major industrial customers on an annual basis about the form and content of their charges, with a view to ensure that the costs are fairly allocated and to consider options to improve service and reduce costs. In all cases, no immediate growth was forecast and the current level of reliability and security is considered acceptable Summary The consumer service level targets reflect customers expectations of service levels, the current service levels provided by the network and Top Energy s expectations of the service level improvements achievable by the service level improvement initiatives currently in place. 87

90 4.4.2 Justification for Asset Performance and Efficiency Targets Loss Ratio LEVEL OF SERVICE The short-term loss ratio targets in Figure 72 reflect a slight improvement on the current loss ratio of the network. Longer-term improvements are expected to result from the impact of the network development plan described in Section Operational Expenditure Ratio Top Energy s operational expenditure ratio is likely to rise to approximately 4.75% in the current year (FYE 2012), due to the impact of additional operational expenditure for the vegetation management programme and other maintenance initiatives. It was expected that, from FYE 2013 and beyond, the operational expenditure ratio would reduce significantly, as a result of the completion of the three year vegetation management cost and an increased level of asset replacement resulting from the network development plan However, the acquisition of the Transpower assets on 1 April 2012 is likely to impact Top Energy s operational expenditure ratio and, at this stage, it is not clear what the appropriate targets should be for the planning period. It has therefore been decided to retain the FYE 2012 target of 4.75% for FYE 2013 and to target a modest improvement in the operational expenditure ratio over the remaining years of the planning period. However, these targets will be kept under review and may need to be reset over the next two or three years, as Top Energy gains experience in the operation and maintenance of its new 110kV transmission assets. 88

91 NETWORK DEVELOPMENT PLANNING Section 5 Network Development Planning 5 N e t wo r k D e v e lo p m e n t P la n n in g Planned Expenditure Routine and Preventative Maintenance Refurbishment and Renewal Maintenance Specific Customer Initiated Projects Augmentation Planning Criteria Voltage Criteria Security of Supply Network Capacity Requirements Network Protection Requirements New Equipment Standards Distribution Policy on Acquisition of New Assets Project Prioritisation Methodology Major Projects Incremental Capital Upgrades Assess Importance and Identify Options Prioritisation Matrix for Network Expenditure The Approach Demand Forecast Overview Data on Historic Demand Forecast Methodology Demand Forecasts Uncertainties in the demand forecast Distributed and Embedded Generation Non-network Options Network Development Plan Introduction Work Recently Completed or Underway Network Development Plan Objectives Northern Area Supply Security Wiroa 110 kv Substation Replacement of Transmission Assets

92 NETWORK DEVELOPMENT PLANNING 5.8 Project Time line and Costs Detailed Project Descriptions and Development Timeline kV Sub-transmission Line Projects (inc 110kV) kV/33kV and 33kV/11kV Substations Distribution Network Reinforcement Reinforcement of the Supply to Russell Network Communications/SCADA/Security Projects Transmission Projects Asset Replacement Projects Future Network Communications System Breakdown of the Capital Expenditure Budget

93 2011 (Budget) 2011 (Actual) 2012 (Budget) 2013 (Forecast) 2014 (Forecast) 2015 (Forecast) 2016 (Forecast) 2017 (Forecast) 2018 (Forecast) 2019 (Forecast) 2020 (Forecast) 2021 (Forecast) 2022 (Forecast) NETWORK DEVELOPMENT PLANNING 5 Network Development Planning 5.1 Planned Expenditure This section considers the works required to augment the existing Top Energy Network to meet forecasted load increases and target reliability levels and also to ensure statutory and business requirements are met. Expenditure is also required to ensure that sufficient asset redundancy is available to ensure that supply to customers can be maintained when a critical network element is out of service either for maintenance or as a result of an unplanned network fault. This is consistent with good industry practice. Top Energy categorises the expenditure into eight expenditure categories as follows: Customer Connections (CU) System Growth (EX) System Reliability, Safety and Environment (RS) Asset Replacement and Renewal (RR) Asset Relocations (RL) Routine and Preventative Maintenance (MP) Refurbishment and Renewal Maintenance (MR) Faults (F) Maintenance schedules and expenditure is covered in greater detail within Section 6 of this AMP, however, Figure 78 and Figure 79 illustrates the predicted levels of expenditure for the planning period, separating the expenditure into the categories mentioned above. 40,000,000 35,000,000 30,000,000 25,000,000 20,000,000 15,000,000 10,000,000 5,000,000 - Fault and Emergency Maintenance Refurbishment and Renewal Maintenance Routine and Preventative Maintenance Capital Expenditure: Transmission Capital Expenditure: Asset Relocations Capital Expenditure: Reliability, Safety and Environment Capital Expenditure: Asset Replacement and Renewal Capital Expenditure: System Growth Figure 78: Expenditure Forecast (FYE 2011 to FYE2022) 91

94 NETWORK DEVELOPMENT PLANNING CAT EXPENDITURE DESCRIPTION FYE 2013 FORECAST ($K) CU Customer Connections 1,045 EX System Growth 11,822 RS Reliability, Safety and Environment 6,597 RR Asset Replacement and Renewal 3,000 Transmission 6,706 Capital Expenditure on Asset Management 29,169 MP Routine and Preventative Maintenance 3,560 MR Refurbishment and Renewal Maintenance 1,135 F Faults 1,200 Operational Expenditure on Asset Management 5,895 Total Expenditure 35,064 Figure 79: Expenditure Forecast Breakdown FYE 2013 It must be recognised that this AMP is a planning document, based on best information currently available, such as predictions of the expected growth in load, location of customers, etc. The identification or inclusion of any project or proposal in the AMP does not oblige TEN to implement it. The Company will continue to review planned projects both in relation to any proposed solution, its timing value to Top Energy and its present and future customers. It should be noted that system planning is a dynamic process depending on several factors including changes in load, equipment condition, advances in maintenance management practice and technology Routine and Preventative Maintenance Routine and preventative maintenance work is primarily based on condition assessment of all the network assets. TEN s maintenance philosophy and strategies are discussed in Section 6. Maintenance expenditure is a major component of TEN s expenditure and is presented as part of the expenditure in Figure Refurbishment and Renewal Maintenance Refurbishment or renewal of network assets is based on condition assessment. The refurbishment and renewals policy adopted by TEN is discussed in Section 6. While asset refurbishment and renewal is treated as maintenance for management purposes, expenditures are treated as capital expenditure in accordance with generally accepted accounting principles Specific Customer Initiated Projects These projects involve the extension of the existing network with new assets to provide for new customer connections, subdivision reticulation and roading alterations. TEN considers possible non-network options such as local generation, to see if they are economically and practically acceptable before agreeing to any project. These projects, because of their basic unpredictability, can rapidly alter the priorities applied to augmentation projects. For example, a developer building a hotel and requiring a 500kVA load at any of the quiet pristine beaches in the Top Energy area, could necessitate a significant network augmentation project to ensure voltage compliance. An annual estimate of customer connection contributions is included in the capital budgetary allowance. TEN may, at its discretion, supplement the requirements of a customer driven project with an internally funded network refurbishment or augmentation. 92

95 NETWORK DEVELOPMENT PLANNING Augmentation Augmentation includes the covers all the work required to enhance network capacity and meet future load growth on the system. Augmentation projects (EX and RS) are initiated to: Improve the capacity of the existing network, Improve voltage control and quality, Improve security of supply to the customers, Improve system reliability. 5.2 Planning Criteria Planning criteria for network development projects are governed by legislative and internal requirements, such as voltage compliance, security of supply, and technical constraints such as maximum current ratings. While load growth is the main factor that drives these requirements, network development is also driven by a need to improve the reliability of supply to customers Voltage Criteria Top Energy uses the following design voltage limits. 33kV sub-transmission: +4.5%, -10% of nominal voltage, 11kV distribution: +2%, -5% of nominal voltage, 400V LV network: ±4% of nominal voltage up to legal point of supply. The voltage limits defined above allow TEN s voltage control equipment, such as on load tap changers (OLTC) in zone substation power transformers, voltage regulators and capacitors on distribution feeders, to keep voltages within statutory limits. TEN s voltage compliance related projects are mainly justified by the following benefits from improved voltage levels or voltage control. the ability to meet statutory voltage limit requirements, improvement in distribution circuit capacity, improvement in back feed ability to other distribution circuits in a contingency situation, and reduction of power losses. Because of the length of feeders, low voltage is generally the first indicator of an emerging network capacity issue and voltage is therefore the most common driver for augmentation projects Voltage Control Options c) Zone sub and Distribution Transformer In order to control the system voltage within the specified limit, Top Energy purchases zone substation transformers with a 15 step on load tap changer (OLTC) facility, with tap ranges from -16.5% (voltage boost) to +4.5% (voltage buck) to keep the distribution network voltage within the required limits. Distribution transformers are rated at 240V and typically have a six step off load tap changer facility with -7.5% (voltage boost) to +5% (voltage buck). d) Distribution Voltage Regulator Top Energy uses two different types of distribution voltage regulators on long rural distribution feeders: 93

96 NETWORK DEVELOPMENT PLANNING Single phase 32 step regulators with tap ranging from -10% (voltage boost) to +10% (voltage buck) with each tap of 0.625% on the primary side of the regulator. This type of voltage regulator gives fine voltage control over the range and keeps the voltage close to 11kV. Single phase 4 step regulators with -10 % (Voltage boost) tap, with each tap of 2.5% on primary side of the Regulators. This type of voltage regulator gives coarse voltage control and is no longer purchased. Traditionally, TEN has connected voltage regulators in an open delta configuration to obtain 10% voltage regulation on the two phases. As Top Energy has a significant number of two wire and single wire lines, a closed delta configuration is now being used as the standard to achieve balanced voltage output on all three phases up to the maximum 15% regulation. e) Capacitor Banks TEN typically purchases 200kVAr fixed tap capacitor banks to use on rural distribution feeders, but also has a 400kVAr switched capacitor bank with 200kVAr steps. The sites for capacitor banks are chosen to avoid the need to include expensive switching of capacitor banks and to not cause any significant absorption of the 317Hz ripple injection signal used for load control. f) Overhead line upgrades Top Energy s network is predominantly rural, with long radial feeders and significant lengths of two wire and SWER lines. Therefore, to address voltage and capacity problems, Top Energy investigates the following options before determining the most economical and long term suitable solution. convert 2 wire and/or SWER lines to 3 wire, use of capacitors and regulators, rearrange feeder routes close to substations to share load more evenly, increase the conductor size at critical areas to remove constraints, or upgrade the operating voltage on heavily loaded sections of line e.g. from 11kV to 22kV, Security of Supply TEN s security of supply criteria drives not only existing asset improvements, but also the design criteria for network extensions and improvements. The criteria require all zone substations with a load greater than 5MVA to have two supply transformers and two incoming 33kV circuits. In the event of the loss of any one transmission element, such as a transformer or incoming line, supply to consumers should not be interrupted. This requires that the contingent operation rating of each substation transformer should be sufficient to carry the peak load of the substation and that there be sufficient transfer capacity within the distribution system so that some load can be transferred to neighbouring substations, to reduce the load of the transformer remaining in service to below its normal rating. In practice there is limited transfer capacity within the distribution network, because of the sparsely populated rural nature of Top Energy s supply area. This limits the level to which transformers can be loaded under normal operating conditions. Where the load at a zone substation is less than 5MVA, a single transformer and single incoming line is permissible. In the event of a single element outage, all consumers supplied from that substation will experience an interruption that could last for up to 10 hours, depending on the cause of the fault and the location of the substation. In most situations, some power transfer capacity within the distribution network will be available, allowing power to be restored to some consumers well before this. Top Energy owns and operates a 7.5MVA mobile transformer unit, which limits the maximum outage duration should a fault occur in a single transformer substation. The time required to relocate this unit from its present location to provide backup to other single transformer zone substations in the event of transformer failure is up to 10 hours. This includes the time required for packing, travelling from one zone substation to another and the time required for assembling and connecting the unit at its new location. The network does not currently conform to the security of supply criteria, due mainly to protection constraints that limit the way the 33kV sub-transmission network can be operated. The sub-transmission system is currently run in a radial, split bus arrangement with one line feeding each half of a substation. This means that, in the event 94

97 NETWORK DEVELOPMENT PLANNING of a fault on the incoming line, supply to approximately half of the customers supplied from the substation would be interrupted until the network can be reconfigured by switching. The inability to maintain uninterrupted supply from large zone substations in the event of a single element fault is a significant concern and is being addressed as part of the network development plan detailed later in this chapter. It is planned to achieve the security of supply standard detailed above within the 10 year planning period. This will involve an upgrade of the protection system at each substation and, in some cases, circuit breaker replacement. The first zone substation to be upgraded to achieve full uninterrupted N-1 security will be Haruru, where the upgrade is currently in progress and targeted for completion by 31 March Consistent with standard industry practice, the network is not designed to cater for simultaneous outages of more than one transmission or sub-transmission element. Should such a situation arise, emergency plans would be activated to restore supply to affected consumers as quickly as possible. However, in such an event, outages of more than 10 hours are possible. Figure 80 shows the level of security currently available at all Top Energy s zone substations. SUBSTATION TRANSFORMER FAILURE BACK UP TO AFFECTED TRANSFORMER TIME REQUIRED TO RESTORE SUPPLY (HRS) Southern Area Kaikohe T1 T2 Switching Time T2 T1 Switching Time Kawakawa T1 T2 Switching Time T2 T1 Switching Time Moerewa T1 Mobile Sub 9.0 Waipapa T1 T2 Switching Time T2 T1 Switching Time Omanaia T1-1 R Mobile Sub 9.5 T1-2 Y T1-3 B Mt Pokaka T1 Mobile Sub 9.0 Haruru T1 T2 Switching Time T2 T1 Switching Time Ngawha T1 Mobile Sub 9.0 Northern Area Okahu Rd T1 T2 Switching Time T2 T1 Switching Time Taipa T1 Mobile Sub 9.5 Pukenui T1 Mobile Sub 10.0 NPL T1 T2 Switching Time T2 T1 Switching Time Figure 80: Security Provided at Zone Substations 95

98 5.2.3 Network Capacity Requirements. NETWORK DEVELOPMENT PLANNING With ever-increasing load growth on the distribution network, some of the existing network assets need to be upgraded, or new assets need to be introduced, to supply the forecasted load growth. For design purposes, TEN considers the different capacity constraint levels on primary assets for normal operation and contingent operation and applies the more restrictive of the two. ASSET TYPE CONDITION PERCENT OF NOMINAL CURRENT RATING Normal operation Contingent operation Transformers Nominal Overhead Conductors Still Air 30 degrees Underground cables In Duct Circuit Breakers Nominal Figure 81: Top Energy Design Capacity Limits Network Protection Requirements Modern protection systems offer features not available from Top Energy s traditional protection relays. Top Energy plans to replace the existing relays with relays that will facilitate utilisation of interties at sub-transmission level and allow more sophisticated meshed switching arrangements at zone substation and distribution levels to reduce the number and duration of outages and meet the requirements of TEN s security standards. The new systems also provide improved data on asset utilisation and will allow improved modelling of the network over time. Improved modelling will mean improved asset management. Protection upgrades are required at all dual transformer zone substations before they can provide uninterrupted N-1 security New Equipment Standards In order to maximise cost efficiencies and reduce the required number of spares, TEN has developed and adopted equipment supply standards for the capacity and rating of stock issue equipment, such as power transformers, conductors, cables and poles. Distribution transformers follow the ISO standard sizing. Pole mounting of new transformers is now limited to 100kVA for seismic reasons. Transformers may be one, two or three phase according to customer or load requirement. Appropriately rated isolating transformers are used to isolate SWER circuits from the rest of the network. Pad (berm) mounted transformers are steel cabinet enclosed units and may include switch units (total pad type) depending on the application. XLPE cables are used as standard for all voltages. HV cables and larger LV cables are aluminium and 33 kv cables are single core for flexibility and ease of installation. LV copper cables in the smaller sizes are used for the customer connections. Wood poles are being progressively phased out of the network. New concrete poles are all pre-stressed I section poles and are generally used at sub-transmission voltage and below. Steel poles will be used for 110kV transmission lines and will also be used for new sub-transmission lines in locations where Top Energy s standard concrete poles do not meet the design requirements. Overhead conductors are currently all aluminium conductor (AAC), except where long spans demand higher tensions. For these applications, the equivalent steel reinforced aluminium (ACSR) conductor is used. For new transmission and sub-transmission lines, all aluminium alloy conductor (AAAC) has been adopted as standard. Zone substation transformers have been standardised as 11.5/23MVA units, except for small sites where this capacity is not warranted and where 5/10MVA and 3/5MVA transformers are used. 96

99 NETWORK DEVELOPMENT PLANNING Network development is planned around TEN s standard asset sizes. In selecting the appropriate asset size, the forecast peak load under contingency conditions at the end of the allowed planning periods (specified in Section 2.30 in the Commerce Commission s ODV Handbook) is generally used as the basis for design and standard asset sizes that avoid the risk of optimisation are normally used. 5.3 Distribution Top Energy s network is predominantly rural and radial with many long feeders, often with a low number of customers per kilometre. This means that the limiting factor determining the size of conductor will be the voltage drop along the line, rather than the thermal current carrying capacity. The company monitors the voltage level along its feeders by using sophisticated computer models and by physically installing data logging devices. Investment made to meet the legally set voltage requirements for the forecast load include converting parts of feeders from 11kV to 22kV, use of voltage regulators and the use of both fixed and switched capacitors. Load growth in many areas has now reached the stage where incremental augmentation of this nature is no longer sufficient. The network development plan will address this issue by increasing the number of points at which power is injected into the distribution network. This will allow the use of shorter feeders, which will limit voltage drops and allow higher current loadings of existing conductors. Top Energy is also planning to install more interconnections between distribution feeders to permit more operating flexibility during faults. This will improve reliability by allowing supply to be restored sooner for many customers after a fault occurs. TEN also monitors the thermal limit current ratings of feeders, which can be a limiting factor for shorter, urban feeders. 5.4 Policy on Acquisition of New Assets The company maintains a system of procurement authorisation for individuals within the overall approved business plan. A job authority system controls authorisation of expenditure on major projects. 5.5 Project Prioritisation Methodology The network development plan can be categorised into major projects and incremental upgrades. Major projects are one-off, individually designed major augmentations or upgrades of the transmission or sub transmission networks. Projects are allocated individual budgets and generally have long lead times. Incremental upgrades are smaller, have shorter lead times and are managed within budget envelopes provided in the Annual Plan. As budgets for network development and augmentation are typically limited, project prioritisation is one of the key functions of asset management. Prioritisation determines the ranking of one project compared to another in the most practical and feasible way possible, and also determines whether a project is included in the AMP and the timing of implementation Major Projects Major projects are prioritised by the Network Planning Manager and his staff with the objective of meeting the strategic objectives approved by the Board and set out in this AMP, with the least lifecycle cost. The primary drivers for this work are: improvement of supply security to the northern region, which is currently constrained by the existence of only one 110kV circuit between Kaikohe and Kaitaia, the significant load growth in the Kerikeri area and the consequent development of a voltage constraint under certain N-1 contingency situations, 97

100 NETWORK DEVELOPMENT PLANNING the need to provide additional security in the Taipa area, where the peak demand is approaching 5MVA, which is the maximum load for a single transformer substation, the age and condition of the single phase supply transformers at Omanaia, a need to reinforce the existing distribution system in the Kaeo-Whangaroa-Matauri Bay and Russell areas. These areas, located on the rapidly developing eastern coastal strip, are experiencing high load growth, but are not currently served by a zone substation, and a need to improve reliability of supply, despite improvement made to-date, reliability is still the lowest of any New Zealand EDB. The major projects planned for the next 10 years and the basis for their prioritisation are discussed in Section Incremental Capital Upgrades Incremental capital upgrades generally have short lead times and are managed within budget envelopes in the Annual Plan. As there are always more potential projects than can be funded from the budget, a process is needed to ensure that only projects that provide the greatest benefits are implemented Assess Importance and Identify Options Top Energy receives information regarding work required on the network from the following sources. TEN staff, Top Energy control centre, TECS, Network lines inspectors, Maintenance Manager, Network modelling and study, Customers, and Far North District Council Plans. This information is used by TEN staff to identify needs and formulate potential solutions for inclusion in the work programme. A project initiation sheet is prepared for each project being considered for implementation, which: fully describes the issue and/or opportunity, identifies the primary driver of the issue (e.g. voltage, compliance, security, reliability), describes the proposed solution and the alternative options considered, including possible non-network solutions, estimates the cost of the proposed solution, describes the benefits of the solution to Top Energy, its customers and the community, and provides a rating in each of the categories within the prioritisation matrix to indicate the impact on the business drivers. The priority of the project is undertaken by assessing the impact of the issue/opportunity against the primary investment drivers, utilising the impact assessment criteria established in the network project prioritisation framework Prioritisation Matrix for Network Expenditure Using the balanced scorecard concept, the four focus areas are utilized to develop the network performance scorecard as shown in Figure 82 below. The key performance indicators (KPI) or business drivers for a network asset management business can then be seen as falling into a number of broad categories as follows 98

101 NETWORK DEVELOPMENT PLANNING Financial The Company needs Revenue Control of costs Return on Investment Customers Meeting customers needs from a network or electrical system perspective Community Supply capacity Quality of supply Reliability of supply Security of supply Being a good corporate citizen Other Stakeholders This in particular refers to government and regulators ensuring that the company meets its minimum legislative and regulatory requirements. This is often an issue of good corporate governance and risk management. These business drivers sit at the top of the network performance scorecard shown in Figure 82 below. They are used as the basis for the prioritisation matrix shown in Figure 83, which in turn can be used to assign a numerical priority ranking to individual projects. The priority of each project is then determined by its priority ranking. N e tw o rk P e rfo rm a n c e S c o re c a rd BUSINESS RESULTS C O M M E R C IA L R E T U R N S F O R O U R S H A R E H O L D E R S O P T IM U M B U S IN E S S R E S U L T S MEET REVENUE CAP CONTROL COSTS MEET ROA TARGET CUSTOM ER FOCUS L O Y A L H IG H L Y S A T IS F IE D C U S T O M E R S C U S T O M E R A N D COMMUNITY FOCUS MODEL COPORATE CITIZEN M E E T C U S T O M E R E XP E C T A T IO N S MEET COMMUNITY O B L IG A T IO N S M A N A G E A L L S T A K E H O L D E R S IN T E R N A L P R O C E S S E S A N D SYSTEM S K E Y P R O C E S S E S A N D S Y S T E M S T O S A T IS F Y C U S T O M E R S A N D E N S U R E O P T IM U M B U S IN E S S O U T C O M E S A S S E T D A T A IN F O R M A T IO N & K N O W L D G E A N A L Y S IS & D E C IS IO N M A K IN G E F F IC IE N T & E F F E C T IV E ASSET MANAGEMENT P R O C E S S E S P R IO R IT IS E A C T IV IT IE S & CREATE THE POW M A N A G E T H E D E L IV E R Y OF THE POW P E O P L E L E A R N IN G & GROW TH IM P R O V E D A S S E T M A N A G E M E N T C A P A B IL IT Y H IG H P E R F O R M IN G T E A M S A N D L E A D E R S W H O D E L IV E R R E S U L T S F L E X IB L E & M O T IV A T E D W O R K F O R C E A C C O U N T A B IL IT Y & P E R F O R M A N C E M A N A G E M E N T C O M M U N IC A T IO N C O N T IN U O U S IMPROVEMENT & T E A M W O R K S A F E T Y P E R F O R M A N C E IM P R O V E D S T A F F C O M P E T E N C IE S Figure 82: Network Performance Scorecard 99

102 NETWORK DEVELOPMENT PLANNING Each of the Business Drivers and their sub-categories are described in more detail as follows: Community & Customer Perception Improved Customer Responsiveness Customer service This category covers any projects that are initiated to improve responsiveness. Examples in this area would include installation of a recloser with SCADA. Whilst it is recognised that this improves reliability, it does also improve responsiveness to customer outages in remote areas, Customer education / consultation costs associated with Community Consultation, public relations, publicity campaigns, Call Centres ensuring that customer s calls are dealt with expeditiously with good up-to-date information being provided to callers, Control Centre expenditure on SCADA systems and trouble management support systems. Improved Visual Amenity Discretionary Under grounding of existing overhead or above ground assets, Additional expenditure over and above the minimum cost solution for new works. Network related issues for Improving Company Reputation This could include community consultation and sponsorship initiatives (eg. Helicopter Appeal, Tall Poppy, and Water Safe). Financial Benefit to Business This explores the Asset Life Cycle costs that focus on optimum design, development, maintenance and retirement decisions for all our assets and specific asset components in order to deliver improving value. Specifically the project should be examined on the basis of its contribution in the following three areas: Reduction in Maintenance Costs, Reduction in Operational Costs, Reduction in future Capital Costs. Meeting Customers needs (from a System Performance perspective) Capacity Load Growth Overcoming Existing Constraints Customer Generated Work LV augmentation Dist sub upgrades Reliability a. SAIDI (System Average Interruption Duration Index) b. CAIDI (Customer Average Interruption Duration Index) c. SAIFI (System Average Interruption Frequency Index) d. MAIFI (Momentary Average Interruption frequency Index) e. ACNABO (Average Customer Numbers Affected by Each Fault) Quality Security Ensuring Regulatory Compliance Safety Staff and Contractors 100

103 NETWORK DEVELOPMENT PLANNING Public Environment The Prioritisation Process is about assessing each project on 13 key aspects of the Business Drivers, giving it a score in each of these areas and thus a score as to how well that project will contribute to the overall business outcomes of the company The Approach The prioritization can be carried out individually or in a team situation. Generally a team situation including all the information sources used by Top Energy is preferable as this ensures that a number of different views are considered and the proposed work scored as objectively as possible. As the Annual Plan is developed with each of the individual projects ranked in order of priority, it will be recognized that conditions will change and in fact there will be a need to revisit some project rankings from time to time. Thus the ranking of capital projects within the Annual Plan is reviewed quarterly. 101

104 NETWORK DEVELOPMENT PLANNING Ranking Not applicable 0 Low 1 Medium 2 High 3 Very High 4 High/Extreme 5 Score Overall Score Network Works Prioritisation Matrix Community & Customer Perception Financial Benefit to Business Improved Improved Improved Reduction in Reduction in Reduction in Impact on System Performance Customer Visual Company Maintenance Operational Future Capital Capacity Reliability Quality Security Staff & Responsiveness Amenity Reputation Costs Costs Costs Contractors Regulatory Compliance Safety Environmental Public Not applicable Not applicable Not applicable Not applicable Low impact only Medium impact only High level of customer and community acceptance expected Very High level of customer and community acceptance expected Extremely high level of customer and community acceptance expected No payback ever Payback within 20 years Payback within 10 years Payback expected within 5 years Payback expected within 2 years Minor customer impact on rare occasions Unable to meet customer needs occasionally Supply failure to small areas occasionally Unable to meet customer needs at times Supply failure to some areas is likely Unable to meet customer needs at times supply failure to key areas impacts service targets Unable to meet customer needs extended supply interruptions Consequences which can be dealt with by routine operations Consequences threaten the ability of the company to meet it's current year objectives Consequences threaten the ability of the company to meet it's short term objectives Major breaches of law resulting in fines significant environmental impact Major breaches of law resulting in jail or major environmental damage Total Score 10 Total Score 13 Total Score 17 Total Score 11 Weighting 0.2 Weighting 0.2 Weighting 0.3 Weighting Figure 83 Example of Network Prioritisation Matrix 102

105 NETWORK DEVELOPMENT PLANNING 5.6 Demand Forecast Overview Load forecasting is performed to provide an approximation of future loads, which is essential for prudent planning. Electricity demand is largely dependent on: economic conditions, weather patterns, and technology release and adaptation into society (e.g. heat pumps, electric cars, etc.). Historically, the methodology used for forecasting demand was based on linear trending of historical data (with the addition of new loads), based on ICP numbers and associated load per customer. The methodology used this year varies from that used previously, as it uses historical base load projections based on the average changes in the past three years. The financially restrained economy has resulted in unpredictable and somewhat hindered growth and demands. Therefore, the period 2009 to 2011 was used as a historical footprint for future load growth, as it provides a more realistic indication of a recovering economy post the 2008 financial recession. TEN takes a careful and rigorous approach to developing future load projections based on historical trends and available information about likely new connections in near future. The following factors are reviewed and considered as appropriate in the development of the forecast: Energy Sales Records: Energy sales records for as many historical years as available for the entire network, mainly by industrial and domestic customer class, are reviewed. As detailed energy sales records are not available for small commercial customers, they are considered as domestic customers. Demand Records: Daily half hourly average demand data for each feeder on the network is obtained from the SCADA system. TEN uses demand data gathered since 2002 for forecasting purposes. The half hourly data for each feeder (with all switching aberrations removed) is then aggregated to obtain the zone substation and feeder demand for any particular period. The average of 12 highest peaks per month is calculated to obtain monthly peak for each zone substation and feeder. The maximum value of the monthly peak is chosen for any particular year to obtain the yearly normalised peak. Regional growth in ICP numbers: The change in ICPs per feeder is obtained from Top Energy s ICP database. ICP per feeder data is available for each year from the year 2000 and used for forecasting purposes. This is used to calculate the demand per ICP for each feeder and each zone substation on the network. Subdivision activity: Any known subdivision activity is tracked down by feeder for the planning period from different resources such as TECS, subdivision developers, real estate agents and TEN s own local knowledge of the region. In cases where the total load requirements for any subdivision is not available, the values of 4kW/unit after diversity maximum demand (ADMD) and 8kW/unit ADMD are used for domestic and small commercial subdivision respectively, as per TEN s design standard. Change in load per customer: Any changes in load per customer (load/ ICP) are calculated using historical demand data and historical change in ICP numbers per year for each feeder and zone substation. The demand of any major commercial or industrial ICP on any particular feeder is considered separately and removed from the total feeder demand to obtain a load per customer value for domestic customers. The forecasting model uses the average of last five year s load per customer value and assumes that the annual change in load per customer will continue into the future. Industrial and large commercial growth: TEN consults with its major three industrial customers regarding any future expansion and change in load demand for the planning period. It also acquires the information on any known industrial and/or major commercial development on the network in near future by consulting TECS and other developers in the region. General demographic and economic trends: TEN uses general knowledge gained from demographic trend information. This information is collected from both publicly available census data and from the data gathered by TEN itself through its daily operations. TEN has also engaged an external consultant to 103

106 NETWORK DEVELOPMENT PLANNING obtain detailed forecasts on population, number of households and economic activity in the region. The final forecast is an aggregate, after diversity, projection that takes into account the above factors. Diversity Factor: Diversity factor is the ratio of non-coincident maximum demand ( feeder maximum demand) to coincident demand (zone substation maximum demand). Maximum demand for different supply points (GXPs, zone substations or feeders) do not necessarily occur at the same time. This suggests that the zone substation maximum demand will be less than the sum of individual feeder maximum demands supplied from it. This also applies to GXP level as GXP maximum demand will be less than the sum of the individual zone substation maximum demands supplied from it. Diversity factors at GXPs and zone substation levels are calculated using historical data for each year. The average of historical diversity factors is applied at appropriate level to forecast maximum demands at zone substation and GXP level. Demand Side Management (DSM) Plan: Load control is effectively limited by hot water storage system ripple relays. The reality is that the majority of consumers do not have sufficient price incentives to modify their demand themselves. However, the three largest industrial consumers are given the opportunity and a direct financial incentive within their tariff structure to contribute to a reduction of grid exit point costs, by controlling their coincident peak loads. Thus far, a more sophisticated real time monitoring and demand side dispatch system is not considered worthwhile. TEN s demand management Plan is discussed in detail in Section 5.7. The load forecast in this AMP includes the impact of these demand management initiatives. This impact is significant in TEN estimated that its load control reduced its actual perk demand by 10MW. Supply- Side Options: Potentially, new large generators have an opportunity to share the benefits of reducing grid exit point charges and this will be negotiated with proponents on a case by case basis. The connection requirements for distributed generation and the approval process, is described later within this section and Top Energy s distributed generation policy is available on the Top Energy website. Top Energy also encourages the connection small generation plant such small 2-5kW generators, solar panels, island generators (<300kW) and small wind mills to its network. TEN has received a number of enquires about distributed generation proposals but the economics of connecting the schemes have not been viable to date and therefore are not included within the forecasts included in this AMP.. Supply-side options are discussed in more detail in Section 5.7. Impact of Uncertain Projects: There are three projects that have the potential to significantly change the load forecasts projected within this AMP. These are discussed in Section Data on Historic Demand Historic demand data for the Kaikohe and Kaitaia transmission substations, as well as the injection into the network from the Ngawha power station, was obtained from the Electricity Authority s centralised data set. Data was also obtained from TEN s SCADA system. Adjustments were made to eliminate false peaks caused by unusual network configurations as a result of switching and also to account for discrepancies between TEN and Transpower data, which occurred as a result of a combination of: losses within the network, inaccuracy in zone substation measurement instruments (as these are not metering class), inaccuracy in time stamps, and inaccuracy in the power factor and voltage assumed for converting GXP data to kva Forecast Methodology Feeder Demand Growth Actual growth rates for each feeder over the period was assessed on the basis of the average of the top 20 normalised feeder peaks for each year. These growth rates were used as the basis for forecasting the underlying growth on each feeder with the base load for the projection being the average of the top 20 feeder 104

107 NETWORK DEVELOPMENT PLANNING peaks in Where the average growth rate over the period was negative, a zero growth rate was assumed. Known new block loads are then added to the underlying growth forecast. However, economic development in the area is currently relatively subdued and, while Top Energy is aware of a number of potential loads, none have progressed to the stage where it has been considered prudent to include them in the forecast. There are also a number of recently completed subdivisions, generally in areas where current load is relatively high. These subdivisions are relatively small and no specific provision has been made for this new load, as new subdivisions can take some years to be fully occupied. In general, it has been assumed that the effect of new subdivision development is to make land available so that load growth in more rapidly developing areas can be sustained. Feeder peak demands generally occur at times when demand is managed through the use of the ripple frequency controlled load management system. If this system was not operational, Top Energy estimates that the forecast network peak demand would be approximately 10MW higher than shown in this AMP Zone and Transmission Substation Demand Growth A feeder to zone substation diversity factor was calculated for each feeder based on the average contribution of that feeder (relative to peak feeder load) to the zone substation peak load for each year of the three year period The demand at each zone substation was the aggregate of the diversified feeder loads for each year of the forecast period. The individual zone substation growth rates were then cross checked at a high level and adjustments were made where it was considered appropriate. In particular, the forecast growth rate at Taipa was increased to 1.25%. This is a popular holiday and retirement area that has historically experienced high growth rates, but which has been particularly hard hit by the global financial crisis. There are a large number of vacant housing lots in the area and it is likely that the current rate of growth in electricity demand will increase as economic conditions improve. The zone substation demand forecasts calculated in this manner were then calibrated against the actual peak substation demands in 2011 (FYE 2012) in order to produce the demand forecasts in the Figures below. Zone substation to transmission substation diversities were similarly calculated and used to calculate transmission substation and network peak demands. A similar approach was also used to estimate the overall network peak demand. Forecast peaks for Kaikohe do not take account of whether or not Ngawha is operating. The peak shown is the potential demand on the grid if Ngawha was not operating at the time of the peak. Under normal circumstances, Ngawha would be operating at time of peak demand and the actual peak demand on the Kaikohe 110kV transformers would be up to 25MW lower than shown in Figure Demand Forecasts Using the methodology described above, the load forecast for each zone substation is shown in Figure 85 overleaf. The peak demands shown in the tables are net of the peak demand reductions that Top Energy is able to achieve though the operation of its load control system. At present, there is no embedded generation within the Top Energy network that supplies an internal consumer load and therefore has the potential to reduce peak network demand. 105

108 NETWORK DEVELOPMENT PLANNING FYE 2013 FYE 2014 FYE 2015 FYE 2016 FYE 2017 FYE 2018 FYE2019 FYE 2020 FYE 2021 FYE 2022 Southern Area Kaikohe Kawakawa Moerewa Waipapa Omanaia Haruru Mt Pokaka Kerikeri (new) Kaeo Northern Area Okahu Rd Taipa Pukenui NPL Figure 84: Zone Substation Demand Forecast (MW) The demand forecasts for the two transmission substations and for the total network are shown in Figure 85 below. FYE 2013 FYE 2014 FYE 2015 FYE 2016 FYE 2017 FYE 2018 FYE2019 FYE 2020 FYE 2021 FYE 2022 Kaikohe Kaitaia Network Figure 85: Transmission Substation and Network Demand Forecast (MW) 106

109 NETWORK DEVELOPMENT PLANNING Transpower GXP Meter Data Obtained TEL Feeder SCADA Data Obtained Utilisation Factor of Feeder Installed Capacity Calculated Proposed New Loads/Load Changes obtained and Utlisation Factor Applied Feeder Load Growth Applied to New Loads/Changes for Period Feeder Load Growth over period Calculated Feeder Load Growth Applied to Base Load Base Load and New Load/Changes Added to obtain Total Feeder Peaks Feeder to Zone Diversity Applied to Forecasted Feeder Peaks to obtain Zone Peak SCADA Data Normalised and converted to kva Data aligned to correct timestamps Diversity of: Feeder to Zone Zone to GXP GXP to Total Network calculated Zone to GXP Diversity Applied to Forecasted Zone Peaks to obtain GXP Peak GXP to Total Network Diversity Applied to Forecasted GXP Peaks to obtain Total Network Peak Figure 86: Load Forecast Methodology Overview 107

110 NETWORK DEVELOPMENT PLANNING Uncertainties in the demand forecast There are three known projects that have the potential to impact the load forecasts projected in this AMP. Both the areas of Purerua and Karikari are subject to potential large subdivision developments that are equivalent to small to medium size townships. Should the subdivisions proceed, a new zone substation will be required in each area. Both developments are currently on hold due to the recession and the current state of the property market. These loads are therefore not included in the demand forecast. The third major uncertainty is potential agricultural and dairy processing at Moerewa, which could increase the load at Moerewa substation by up to 5MVA above the forecast level. This depends on both the resource planning process and the overseas market for agricultural products. At this stage, the chances such processing proceeding are considered most uncertain, therefore the load is not included in the forecast. In the southern network, TEN is aware of other smaller potential subdivisions and industrial loads especially on Aerodrome feeder (800kVA) and Riverview feeder (900kVA). In the northern network, there are also potential subdivision loads on Te Kao feeder (200kVA), North Rd feeder (800kVA supermarket), Herekino feeder (300kVA) and Redan Rd (300kVA). There are also a significant number of subdivision developments already in progress or completed that have not yet resulted in connected load, but which could very quickly add to the present demand, once the recession lifts in the region and building recommences. These developments could result in some increase in forecast growth rates, but can be accommodated by the network development plan as formulated in this AMP Distributed and Embedded Generation The term distributed generation (DG - sometimes referred to as embedded generation) relates to any electricity generation facility that either produces electricity for use at the point of location or supplies electricity to other consumers through a local lines distribution network, at distribution rather than transmission voltages. Top Energy s approach to DG is based on the following key principles: DG is able to connect to Top Energy s electricity distribution network on fair and equitable terms that do not discriminate between different DG schemes, the terms under which DG can connect and operate are as clear and straightforward as possible, within the limitations of maintaining a secure and safe electrical distribution network, all DG applications will be processed as quickly as possible, DG must comply with technical and safety standards based on industry practice, all relevant legislation and regulatory requirements will be adhered to, TEN reserves right to limit the total capacity of DG connected to different parts of its network (in particular to each distribution feeder), and DG installations will be subject to normal industry connection requirements, in particular, those outlined in the Electricity Industry Participation Code. Top Energy has adopted a formal Distributed Generation and Connection Policy and Technical Standards for DG proposals of less than 10kW, in the range 10kW to 500kW and greater than 500kW. These documents specify the: general procedure for applications and installation of DG (refer Figure 87), commercial terms, technical standards, liabilities of Top Energy and the applicant, and health and safety management. Top Energy s policy and requirements for the connection of distributed generation are available on its website at or by ing info@topenergy.co.nz or by calling or visiting one of our office locations in Kerikeri, Kaikohe, Puketona or Kaitaia. 108

111 NETWORK DEVELOPMENT PLANNING Figure 87: Distributed generation connection process Top Energy considers potential supply-side options as an integral part of its project assessment process to determine whether capital expenditure can be deferred and also if maximum demand at GXPs can be reduced. This section briefly discusses Top Energy s policies for supply-side options. Embedded Generation (>5MW): Top Energy encourages the provision of embedded generation by introducing potential consumers to suppliers, consultants and major energy companies that can assist in the development of such schemes. As a company, Top Energy has demonstrated its own commitment to embedded generation by establishing the 25MW Ngawha Power Station. Dispersed Generation options (<5 MW): Dispersed generation provides power to individual or small groups of installations. Where great distances separate potential electricity consumers from each other or from the grid, dispersed generation can be a cost-effective alternative to grid extension. Top Energy s recent installation of a 4MW diesel generator at Taipa substation is an example of this. 109

112 NETWORK DEVELOPMENT PLANNING The following options have potential for dispersed generation, small thermal generators. Generators installed as standby units in hospitals or industrial installations could potentially be synchronized to the network and used as part of a strategy to manage network peaks, solar panels (with or without battery storage). Solar panels connected through an inverter to the network have proved popular in Australia as a result of government subsidy programs. Similar subsidies are not available in New Zealand and the high cost and low output of solar panels means they are currently uneconomic, except in situations where the peak demand at a connection point is below about 1kW, mini and micro- hydroelectric, and wind power. Top Energy has received a number of enquiries about small distributed generation proposals ranging from photovoltaic panels to 1-2MW generator sets, however the schemes have not been economically viable to date. Top Energy uses solar panels for some of its remotely controlled equipment to avoid the cost of a dedicated transformer and on a number of occasions has used mobile generators to provide supply to customers when the network is not available. However, in most instances the costs to implement a micro-generation option make it difficult to convince customers that this would be good value for money. This is usually due to the following factors. physical distances between customers often requires a significant network to be retained or built, capital cost and life expectancy of the technologies, and reliability of the energy source. Top Energy has also found that most customers have an inherent reluctance to change. However, alternative generation sources are an integral part of Top Energy s planning and prioritisation process, especially when security projects are being considered, the Taipa generator is an example of this. In addition, Top Energy has identified its requirements for the connection of distributed generation to the system. Top Energy is aware that supplying uneconomic customers may create a business opportunity to establish distributed generation solutions in place of upgrading old lines. The viability of distributed generation in these circumstances will likely depend on the technology available at the time, whether a line upgrade is required, and the life cycle costs of operating and maintaining the plant to ensure reliable and safe operation Non-network Options Demand side management (DSM) refers to programs or projects undertaken to manage a consumer s demand by changing the time of demand, therefore helping to reduce the network peak or maximum demand. By reducing demand at the network peak time, DSM options can reduce the use of existing network assets at the peak time, deferring the capital investment for additional capacity. The selection of a viable DSM option starts with identification of all appropriate alternatives, their cost and performance characteristics. The development of a market based system by the grid operator to provide load reduction in the event of an emergency loss of generator has provided an opportunity for the use of the ripple control system. As yet, Top Energy does not participate in this demand side management market opportunity, due to the limited load available to be shed within the response time required. However, Top Energy offers different DSM options to its major industrial customers as appropriate, but is currently unable to provide sufficient price incentives for them to modify their demand. Top Energy uses following DSM options to manage customer s demand in different operating conditions. Automated Direct Load Management (DLM): Top Energy has conventional ripple frequency controlled water heating systems. Daily peak-load shedding is based on the GXP peak load. Under emergency conditions, where network components are out of service, Top Energy utilises the system to reduce load and maintain supply for as many customers as possible. Load control relays also delay the restoration of 110

113 NETWORK DEVELOPMENT PLANNING hot water load for a short but random period after a total loss of supply to reduce switching spikes and avoid equipment overload. The ripple control system is routinely used to control the peak demand on the network and Top Energy currently estimates that the system currently reduces the actual demand forecast peak demand on the network by 10MW. Under-Frequency Load Shedding: In order to prevent a total system collapse under major grid disturbance conditions, Transpower requires that automatic tripping of certain percentages of each network s load should occur when an under frequency event occurs on the system This event, for example, could be the failure of a major generation in-feed. In order to comply, the Top Energy system has been configured so that the load to be shed is split into two blocks. These blocks trip after a pre-set delay, dependant on the levels of frequency excursion on the system. Figure 88 below shows the operating arrangements of these two load blocks. Frequency Excursion Tripping Time - Seconds Block 1 Block Hz Hz 4 4 Figure 88: Emergency Load Shedding Specification In terms of the quantity of load interrupted, Block 1 equals approximately 34% of the Top Energy Network maximum demand and Block 2 equals approximately a further 21% of the maximum demand. The Figure below identifies the feeders disconnected by each of the two blocks of emergency load shedding. SUBSTATION BLOCK 1 FEEDER BLOCK 2 FEEDER SOUTHERN NETWORK Kaikohe Horeke Taheke Rangiahua Ohaeawai Kawakawa Towai Opua Moerewa Tau Block Pokapu Moerewa Waipapa Totara North Purerua Riverview Haruru Puketona Onewhero Omanaia Rawene Opononi 111

114 NETWORK DEVELOPMENT PLANNING SUBSTATION BLOCK 1 FEEDER BLOCK 2 FEEDER NORTHERN NETWORK Okahu NPL TAIPA PUKENUI South Road Kaitaia West Herekino Awanui Oruru Tokarau Mangonui Te Kao Pukenui South Figure 89: Top Energy Emergency Load Shedding Feeder Identification The development of a market based system by the grid operator to provide load reduction in the event of an emergency loss of generator, has provided an opportunity for the use of the ripple control system. Stand alone systems: In addition to the above, and with a focus on new ways to meet future power demands on heavily loaded sections of the electricity network, Top Energy is also currently working on a green energy project. If successful, this may see the roll-out of solar power and hot water systems across some targeted areas of the Far North. The project involves trialling a combination of solar photovoltaic panels, solar hot water and battery storage systems to assess the impacts on domestic electricity consumption during peak evening periods. Ten houses in Kerikeri have been identified with the trial sites selected based on the best mix of exposure to the sun, the number of people in the home, including whether there are couples or families with children. The project's ultimate objective is to ease the pressure on the network in the evenings, when consumption is at its peak. If it progresses beyond the pilot stage the scheme will not only boost the amount of green energy used across the region, but will also help meet power demands on heavily loaded sections of the electricity network. Instead of being transported across the region power will be generated and used at a local level. The solar panels will generate electricity from the sun during the day and store it in the batteries. Using a localised PLC Controller with connection through to the Network Control Centre in Kaikohe, Top Energy will then be able to switch-in this power supply to supplement the grid supplies during evening peak load periods. This could be particularly effective in areas where the network is already heavily loaded, such as SWER lines, and reactive enough to be quickly implemented at times of the day when consumption peaks. As far as Top Energy is aware, this is the first time that solar micro generation at a domestic level has been used in New Zealand for load management purposes. The system should also prove useful if or when electric cars become more popular in the future, as it will allow people to charge their cars in the evening using energy collected from the sun during the day. Electricity stored in these batteries could also feed back into the network and reduce peaks. If the project does prove viable, priority will be given to those areas where capacity needs to be expanded but where work isn t scheduled to start within the short term planning window. The initiative could give these areas the scale and security of supply they need, as quickly and efficiently as possible. The solar initiative will also enable people to have greater control over their energy consumption. As part of the project, Top Energy will be studying not only the effects of micro solar generation systems connected to the electricity network, but also any sociological or behavioural aspects. We are interested to see if people change their living patterns to maximise the benefits from generating electricity or heating water from the sun their 112

115 NETWORK DEVELOPMENT PLANNING homes. For example, people may choose to have showers in the evening rather than in the mornings, or run appliances such as dishwashers and washing machines during the day when the sun is shining. The peak consumption and social behavioural effects will be monitored over the next 12 to 18 months to identify if further installations could be rolled out on other areas of the network and defer future investment in traditional but more expensive system upgrades. We will publish the results of the trial as part of future asset management plans, as well as incorporating any future project initiatives in the long-term network development plan. 5.7 Network Development Plan Introduction Top Energy s 2010 AMP presented a 10-year sub-transmission development plan aimed at providing the additional network capacity required to supply the rapidly developing coastal belt to the east of its supply area. However, the plan did not integrate the development of transmission and sub-transmission assets. Such integration was not possible, because Transpower (rather than Top Energy) owned the transmission assets. While the subtransmisson development plan addressed the growth in demand on the eastern seaboard, it was unable to address the impact of the Transpower-owned assets on around one third of Top Energy s consumers, who were reliant on a nonsecure supply due to the single transmission circuit between Kaikohe and Kaitaia. The power supply to Kaitaia and surrounding areas is reliant on the availability of a single 110KV line from Kaikohe. When the line is out of service (either planned or unplanned) 10,800 consumers are without power for the duration of the outage, including Juken Nissho Ltd, Top Energy s largest industrial customer. Consumers connected to Top Energy s northern network are therefore subject to considerable risk of loss of supply due to outages of this transmission line. In addition, the transformers and other equipment at both the Kaikohe and Kaitaia Transpower substations are in a deteriorated state. They are no longer sound and there are no spares available for them in New Zealand. This has been an ongoing issue for Top Energy. Although the Top Energy network investment programme detailed within the AMP2010 was focused on providing sub-transmission capacity for expansion and appropriate security for Far North customers, there was still significant dissatisfaction expressed by customers in the Kaitaia district in relation to the lack of transmission security and the loss of supply which had occurred in recent years. This resulted in complaints to the Minister for Energy, with customers demanding the construction of a second transmission line. Over the last three years, Top Energy has been in consultation with Transpower over the security of supply to consumers in the Kaitaia region. During this time it has engaged in an extensive community consultation process to determine the standard of electricity supply required to underpin the economic development of the Far North over the next two decades and, importantly, the amount its customers are prepared to pay to secure an electricity supply of the quality that other rural New Zealanders have come to expect. The consultation has established that 80% of consumers wish to see the reliability of supply to the Northern area improve. In addition there is also overwhelming support from community organisations for the construction of a second 110 kv circuit to secure the electricity supply to the Kaitaia region. This is evidenced by letters of support received from: The Far North District Council The Northland Regional Council The Top Energy Consumer Trust The Independent Farmers of New Zealand The Electricity Commission confirmed on 28th May 2010 that Transpower and Top Energy had complied with the requirements of rule 5.1 of Section ii of Part F of the Electricity Governance Rules and therefore had clearance to proceed with the development of a second transmission line between Kaikohe and Kaitaia. 113

116 NETWORK DEVELOPMENT PLANNING Two solutions were evaluated for the possible route of a second transmission line, Transpower s existing direct route and a coastal route following Top Energy s planned 33kV network development. The least cost technical solution for this second transmission line was found to be a re-design to 110KV of the previously proposed Top Energy 33KV line, along a coastal route. This proposal represented a $10 million saving over the direct route proposed by Transpower, since a large portion of the coastal route would still be required for 33kV subtransmission development, even if the direct route was used for the second transmission line. Hence the construction cost using the coastal route represents an upgrade cost as opposed to the complete new build cost using the direct route. A new transmission line around the coastal route not only achieves the capacity and security of supply requirements of the existing 33kV plan but has the added advantage of allowing consumers in the east coast region to be supplied from Kaitaia as an alternative to Kaikohe. As a result of this, the coastal route option provides a security of supply benefit to 24,500 (80%) of the network s customers rather than just the 10,800 (35%) that would have benefited from Transpower s direct route. If Top Energy were to construct the proposed 110kV coastal line route, while Transpower retained ownership of the existing transmission assets, then the two transmission lines between the Kaikohe and Kaitaia grid exit points would be under different ownership. This would make both transmission pricing and operational control very difficult to manage. Transpower therefore agreed that the lowest cost and best technical solution was adopted and worked closely with Top Energy to transfer its existing assets in the Far North to Top Energy ownership. The transfer, which (at the time of writing) is planned to take place on the 1 st April 2012, will occur at Transpower s regulatory asset value. Top Energy believes that this transfer will result in significant gains in overall economic efficiency and will benefit all electricity consumers in the Far North. In addition to the issue of the second line, significant investment will also be required to bring the existing substations up to standard. This will require approximately $30 million to be invested at the Kaikohe and Kaitaia substations over 6 years. The projects include: Replacement of the Kaitaia transformers. These currently do not meet security standards, are in poor condition and no spares are available in New Zealand. Replacement of the Kaikohe and Kaitaia 33kV outdoor switchgear with modern indoor equpment, consistent with Transpower s existing safety driven replacement programme. The new indoor switchgear would also provide for termination of new sub-transmission circuits that will still be needed even if the transmission development plan is implemented. Extension of the Kaikohe 110kV switchyard to allow for connection of the new transmission circuit. The acquisition of Transpower s Kaikohe and Kaitaia substations and the 110kV Kaikohe-Kaitaia transmission line gives Top Energy full control of all assets used to deliver electricity to consumers throughout its supply area. Top Energy has replaced its original plan from AMP2010 with a new plan that integrates transmission and sub transmission development to address all existing capacity and security issues in a cost-effective manner. This new network development plan is presented in the following sections Work Recently Completed or Underway The following components of the sub-transmission development plan announced in 2010 have either been completed or are nearing completion. Stage 1 of the new 110kV double circuit transmission line between Kaikohe and Wiroa has been completed. This is the section between the Kaikohe transmission substation and State Highway 1, north of Ohaeawai. Under the original plan, while this line was constructed at 110kV, it was expected to operate at 33 kv for up to 20 years. Under the new plan, this will be operated at 110kV and will form part of the second 110kV circuit between Kaikohe and Kaitaia. A new 33kV sub-transmission line between the Ngawha power station and the Kaikohe zone substation has recently been completed and is awaiting commissioning. This line is intended to address operating and protection constraints inherent in the current configuration and also to provide N-1 redundancy in 114

117 NETWORK DEVELOPMENT PLANNING the connection between the power station and the Top Energy network. Commissioning has been deferred from within the FYE 2011 financial year to maximize the project cost savings through Top Energy acquiring the Transmission assets at Kaikohe. A major protection upgrade of the Haruru zone substation is nearing completion. This will allow the transformers and incoming 33kV circuits to be operated in parallel. Haruru will therefore be Top Energy s first zone substation to provide full, uninterrupted N-1 security. Construction of the new Kerikeri zone substation and the underground sections of the new 33kV circuits to supply it is in progress. Two 2.5MVA diesel generators have been installed at Taipa zone substation to provide backup in the event of a sub-transmission fault. The Taipa substation consists of a single transformer and incoming line notwithstanding a current peak load of almost 5MVA Network Development Plan Objectives Top Energy s integrated network development plan is designed to address the following key network constraints. Approximately 10,000 consumers in Top Energy s northern area are reliant on a non-secure supply, due to the fact that there is only one transmission line between Kaikohe and Kaitaia. The consumers are subjected to annual maintenance interruptions lasting up to 14 hours, as well as an elevated risk of unplanned fault interruptions. The sub-transmission system serving consumers in the Kerikeri area is loaded to its full design capacity at times of peak network demand. As a result, in the event of an unplanned outage of a sub transmission element, the network voltage could drop to an unacceptable level. This problem could only be addressed by shedding load. Many of the assets purchased from Transpower are old and present safety and reliability risks. A particular problem is the capacity and condition of the existing transformers at Kaitaia. These are old single phase units that testing has indicated are in poor condition. They are also rated at 22MVA, which is less than the current load at the substation. The condition of the 33kV outdoor switchgear at both substations is also an issue. Load growth in some areas not well served by existing zone substations is exceeding the capacity of the existing 11kV distribution system. Areas of particular concern are Kerikeri, the Whangaroa-Kaeo-Matauri Bay area and Russell. Apart from Haruru, all zone substations are currently operated in a split bus, radial configuration in order to manage protection constraints. This does not meet Top Energy s security requirements for larger, twotransformer substations as it means that supply interruptions are inevitable whenever a sub-transmission fault occurs. Outdoor switchgear at some substations is in poor condition and requires replacement. Moerewa and Waipapa are of particular concern. The single phase transformer bank at Omanaia is now 58 years old and approaching the end of its economic life. Solutions to these constraints are discussed in the following sections Northern Area Supply Security The dependence of the northern area on a single 110kV line from Kaikohe has been a source of concern to Top Energy for many years. The existing line uses the most direct route and crosses the Maungataniwha Range, where the towers are relatively inaccessible and difficult to maintain. A second 50kV line existed until the 1980s, but was abandoned because of its poor condition and the fact that it had insufficient capacity to provide full N-1 backup. 115

118 NETWORK DEVELOPMENT PLANNING A number of options have been considered at various times to improve security to the northern region. The provision of a source of generation in the area has always been an alternative which, on the surface, appears attractive but has proved elusive. A number of generation projects have been proposed in the past, but none have progressed passed the feasibility stage. The most attractive option is currently wind generation and Top Energy is aware of at least two proposals. However, wind generation is not dispatchable and therefore cannot provide the reliability needed for a credible alternative supply. The construction of a second line by Transpower over the direct route has also been a possibility. However, this option is expensive and difficult to justify, when its only benefit would be to provide a supply when the existing line is out of service. Incremental demand growth is rapidly developing around the coastal belt in the east and north east of Top Energy s supply area. The need to reinforce the network supplying this area has created an opportunity that has not previously existed, as it has made the construction of the second line over a longer, but more accessible coastal route, economically feasible. This is because the line can also supply these coastal communities and, in particular the Kerikeri area, where additional capacity is now urgently required. Transpower s agreement to transfer its assets to Top Energy has facilitated this plan, as it has avoided the constraints and additional costs that would have arisen had a new line over the coastal route been operated as part of the National Grid. In accordance with its 2010 sub-transmission development plan, Top Energy has already commenced construction of a double circuit line between Kaikohe and a new substation at Wiroa. While it was planned to operate this line at 33kV for around 20 years, the line will now likely be operated at 110kV from FYE The new 110kV line to Kaitaia will be a new single circuit line from Wiroa to the existing transmission substation at Pamapuria, south of Kaitaia and will be completed during FYE A potential line route has been identified and landowner discussions will commence shortly. The line will have an underbuilt 33kV circuit over the southern part of its route to supply the new Kaeo substation. As discussed in Section 5.7, the line may also be diverted to the site of a new 110/11kV substation at Taipa. Following completion of the new 110kV line between Kaikohe and Kaitaia, it will be possible to take the existing 110kV line out of service without disrupting the supply to Kaitaia. Top Energy is then planning to refurbish the old line. This is a major project that is expected to take around four years, involving the replacement of poles and other equipment that exhibit significant levels of deterioration Wiroa 110 kv Substation Under the 2010 sub transmission development plan, Top Energy had committed to building a new double circuit line, designed for operation at 110kV, to a new 33kV switching station at Wiroa. The construction of a new switching station at Wiroa was preferred to an earlier plan to upgrade the Waipapa substation, because of difficulty in finding a 110kV line route into Waipapa that complied with Civil Aviation requirements in relation to the construction of transmission lines close to the Kerikeri Airport. As noted above, Stage 1 of this line has now been completed and landowner negotiations for the route for Stage 2 between State Highway 1 and Wiroa are currently being finalised. It is expected that construction of this stage of the line will be completed by FYE A site for the new Wiroa substation has been identified and negotiations for purchase are in progress. The 33kV switchyard is planned for completion by FYE 2014 and will be energised initially by operating the new incoming line at 33kV. There will be five outgoing circuits. The existing 33kV circuits to Waipapa will be diverted into this switchyard, providing two outgoing circuits to Waipapa and one to Mt Pokaka. A new underground 33kV circuit will supply the new Kerikeri zone substation, while the new underbuilt circuit to Kaeo will also be supplied from Wiroa. Construction of the 110kV switchyard is currently planned for completion by FYE 2016, prior to the completion of the 110kV circuit through to Kaitaia by This will have two 40/60MVA (110/33kV) transformers, which will provide sufficient capacity to meet supply the coastal region between Kerikeri and Kaeo (including the rapidly growing commercial and industrial area at Waipapa) for the longer-term. Top Energy has considered the potential to defer construction of the 110kV Wiroa switchyard by operating one circuit of the new 110kV line at 33kV upon commissioning. However, load flow studies have indicated a potential 116

119 NETWORK DEVELOPMENT PLANNING for 33kV voltage collapse in a high load situation when Ngawha is not operating and Top Energy is reliant on the national grid for its incoming supply. Nevertheless, Top Energy will continue to explore options for deferring the Wiroa 110kV upgrade. Transpower s installation of a third 220kV circuit through the Auckland isthmus and the installation of a new STATCOM at Marsden should improve the incoming voltage at Kaikohe. Top Energy is also reviewing the accuracy of its load flow model, a more accurate model may indicate that the issue is not as critical as currently believed Replacement of Transmission Assets As mentioned earlier, some transmission assets being acquired from Transpower are in poor condition. Particularly critical are the Kaitaia transformers, which are old single phase 22MVA banks that do not have sufficient capacity to carry the full 25MW northern area demand under contingency conditions and which tests show are producing excessive amounts of gas, an indicator of insulation deterioration. They are planned for replacement in FYE 2015 with two 40/60MVA three phase units. A further concern is the condition of the 33kV outdoor switchyards at both sites. Outdoor switchyards at this voltage are now considered a safety hazard for maintenance workers, because of the low electrical clearances and the need for maintenance work to be undertaken in close proximity to live equipment. In the last 25 years, there have been four fatalities of workers doing maintenance in Transpower s outdoor 33kV switchyards. The Kaikohe switchyard is now more than 50 years old and replacement of much of the equipment is overdue. Construction of outdoor switchyards at this voltage is no longer considered good industry practice and Transpower has commenced a programme of replacing outdoor 33kV switchyards with indoor switchboards. The replacement of the Kaikohe switchyard with a new indoor 33kV switchboard is programmed for FYE This project will also make the 33kV outdoor switchgear at the adjoining Kaikohe zone substation redundant. Two outgoing 33kV circuit breakers on the new switchboard will connect directly to the high voltage side of the existing supply transformers at the zone substation through short lengths of 33kV cable. The 33kV outdoor switchyard at Kaitaia was constructed in time for the commissioning of the Pukenui zone substation in While the asset is not as old as Kaikohe and is in better condition, the safety and reliability concerns remain and the circuit breakers are nearing the age where replacement will be required. A conversion of these assets from outdoors to indoors is currently planned for FYE Project Time line and Costs Over the next ten years some 17 major capital projects have been identified in the Network Development Plan. These projects will transition the network from its current configuration to the proposed configuration shown in Figure 121 and, deliver the security and capacity improvements required. Project staging has been determined by a number of factors. Most critical were the anticipated timing of the security and capacity constraints on the network, ensuring that the network enhancements will be in place just before the constraints begin to have a negative impact on system performance and customer service. In addition, resource availability (human and financial) was considered and projects moved appropriately. The result is a work plan which will produce the desired performance outcomes in an affordable and sustainable manner. 117

120 NETWORK DEVELOPMENT PLANNING MAJOR PROJECT COST ($M) kV / 110kV line Kaikohe to Wiroa 6.8 Kerikeri Substation and Interconnections kV Line Upgrades (incl Waipapa #1 refurbishment) 3.8 Submarine cable to Russell kV Switchyard and switching station Wiroa kV Substation at Wiroa 5.2 Taipa Substation 5.4 Purerua Substation 2.5 Whatutwhiwhi Substation 1.9 Kaeo Substation and Interconections 7.4 Kaeo 33 kv Lines 2.7 Switchboard Replacement Kaikohe GXP 2.7 Switchboard Replacement Kaikohe GXP 2.7 Transformer Replacement Kaitaia kV Feeder Conversions - Taheke, Russell, South Rd 2.25 TE kv Line Wiroa to Kaitaia kV lines to Kerikeri Substation kv Line to Purerua kV line to new Taipa Substation kV Line to Whatuwhiwhi kV line No 2 to Omanaia 4.6 Figure 90: Major Project Implementation Timeline 118

121 119 NETWORK DEVELOPMENT PLANNING

122 LIFE CYCLE ASSET MANAGEMENT 5.9 Detailed Project Descriptions and Development Timeline kV Sub-transmission Line Projects (inc 110kV) PROJECT NO. DETAILS DRIVER FYE START BUDGETED COST K$ 33KV-UG-KER KV-UG-KER KV-TE2020-DESIGN KV-UG-WRR KV-OH-WRR KV-OH-KAO KV-OH-WPA KV-UG-KER KV-OH-KAO SUB-SWGR-KHE-2014 SUB - New Kerikeri ZS - Construction of KER No 2 33kV line from Wiroa to Hall Rd - Stage 2 EX KER No1 line 3.5 km - WPA Rd to the Sub Site Design and consents RS Wiroa to KTA 110kV - detailed planning and design, consenting - Yr 2 RS kV Cable installation - Sub to A/P Junction - design EX New DBL cct 33k V 110kV line to Wiroa substation site from KOE GXP- Stage 2 EX kV Build new line from gun club to Kaeo site.5.2 km total Construction Phase 1 EX Decommission WPA 1 33kV line - Kaikohe to SH1 RS KER No1 line 3.5 km - WPA Rd to the Sub Site RS kV - Interconnection with 110/33kV Line - design and consenting EX Kaikohe GXP 33kV Switchgear, Building and transformer shift RS KV-CONNECT-KHE kV interconnection design EX KV-UG-KER KV-TE2020-DESIGN-2014 SUB-New Kerikeri ZS-Construction of 100 m of 3 x 1c 630 mm2 Al XLPE from WPA Substation EX Wiroa to KTA 110kV - detailed planning and design, consenting - Yr 3 RS KV-TE2020-STG kV Construction Phase Wiroa to RS

123 LIFE CYCLE ASSET MANAGEMENT PROJECT NO. DETAILS DRIVER FYE START BUDGETED COST K$ KTA Stage 1, 18km 33KV-UG-WRR KV-OH-KAO KV-UG-WRR KV-OH-TPA kV Cable installation - Sub to A/P Junction EX kV Build new line from gun club to Kaeo site. 5.2 km total Construction Phase 2 EX New DBL cct 33kV 110kV line to Wiroa substation site from KOE GXP- Stage 3 EX kV Interconnection Line from Peria to Taipa - 7.5km Design and Easements EX KV-CONNECT-KHE kV interconnection EX KV-TE2020-STG KV-UG-WPA/KAO-2015 SUB-TF1-KTA-2015 SUB-TF2-KTA KV-OH-WPA/KAO KV-OH-TPA KV-TE2020-STG KV-OH-KAO kV Construction Phase Wiroa to KTA Stage 2-24km RS kV - KEO - New UG cable and switch at Waipapa EX kV Substation Kaitaia - 110kV Transformer 1 RS kV Substation Kaitaia - 110kV Transformer 2 RS kV - KEO - Upgrade line ABS to volt 800 amp. EX kV Interconnection Line from Peria to Taipa - 7.5km EX kV Construction Phase Wiroa to KTA Stage 3-12km RS kV - Interconnection with 110/33kV Line km EX KV-CONNECT-KTA kV interconnection RS KV-TE2020-STG KV-OH-PUR kV Construction Phase Wiroa to KTA Stage 4-12km RS Purerua-33kV 8.5km Design and Consents EX

124 LIFE CYCLE ASSET MANAGEMENT PROJECT NO. DETAILS DRIVER FYE START BUDGETED COST K$ 33KV-MARINE-HAR-2018 Russell Submarine Cable and install Design EX KV-OH-HUP-2018 Pakaraka Hupara 33kV tie line RS KV-OH-PUR-2019 Purerua-33kV 8.5km Stage 1 EX KV-MARINE-HAR KV-MARINE-2020 Russell Submarine Cable and install stage 1 EX Russell Submarine Cable and install stage 2 EX KV-OH-WHI kv line - 25km from Pukenui Tee EX KV-OH-PUR-2020 Purerua-33kV 8.5km Stage 2 EX KV-OH-OMA KV-OH-OMA KV-OH-OMA kV - OMA - New 33kV line to Omanaia substation. Design and Property RS kV - OMA - New 33kV line to Omanaia substation. Stage1@ 31 km Total RS kV - OMA - New 33kV line to Omanaia substation. Stage 31 km total RS Figure 91: 110kV/33kV line projects 110KV-OH-WRR: New 110KV line to Wiroa The Northland east coast, Kerikeri town and the Waipapa industrial area are supplied by Waipapa substation and all areas are experiencing significant growth. Waipapa substation is currently being fed by Waipapa#1 and Waipapa#2 33kV lines from Kaikohe GXP, both of which are long lines of insufficient capacity for the current load requirements. There is no spare capacity for projected growth and neither line can carry the full Waipapa substation load on its own should the other fail. To provide for the future load growth in the area and to strengthen the southern sub-transmission network, Top Energy had previously envisaged a new 110kV line from Kaikohe to Waipapa and previous AMP s have reflected this proposal. Reassessment of the 33kV network development requirements during 2009 has explored alternative solutions to the supply issues experienced by Kerikeri, Waipapa and the Eastern Bays (refer section 5.7). The outcome of that exercise has been the development of a plan to construct a double circuit 110kV line from Kaikohe to a new 33 kv switching station at Wiroa (near the Kerikeri Airport) and to operate this line at 33kV for the first 20 years of its life or until demand growth requires additional line capacity. At that time (circa 2035) a 110kV substation will be constructed at Wiroa and the line converted to 110kV though insulator replacement. 122

125 LIFE CYCLE ASSET MANAGEMENT The line and substation will provide a central load hub in Wiroa for the meshed supply of the southern area sub-transmission system and future northern southern area links between Waipapa and Taipa via Kaeo. The double circuit line will be constructed more or less along the original Waipapa No 1 line route as far as SH1, on 18.5m I section concrete poles, and with standoff insulators. To provide for the capacity and impedance required at 33kV the conductor to be used will be Selenium all aluminium alloy conductor (AAAC). The second section of line from SH1 to Wiroa will skirt Waimate North through a valley to the north and will be constructed on taller 20m steel poles. Line easement and resource consent negotiation for Stage 2 is currently in progress. Line survey and design is being undertaken by external consultants, and construction of Stage 1 by TECS is almost complete. 33kV-UG-KER2: Install new 33kV underground cables to new Kerikeri substation site. Top Energy is planning a new substation in the Kerikeri area to improve the network capacity and the power quality in the area. For aesthetic and security reasons it is planned to use underground cable to supply the new substation. One new 33kV cable will be laid from the new Wiroa 33kV switching station to the Kerikeri Substation site on Cobham Rd. The 7km cable will be run in line bored ducts under or adjacent to the road, in conjunction with fibre optic cables and spare ducting for conversion of the 11kV and 400V overhead system to underground at a later date. In the year 2013 a second new cable of approximately 5km is planned to be installed from the new overhead 33kV line from the Waipapa substation (which has recently been constructed) to the new proposed substation site. These completed circuits will connect the proposed substation site to the existing 33kV network via the Waipapa substation and Wiroa switching station ensuring optimal security for Kerikeri. 33kV-OH-KWA2: Kawakawa No 2 Line upgrade. Top Energy plans to upgrade the size of 20km of the conductor on this line to cockroach to ensure that line impedence is such that unit protection operation is assured. 33KV-UG-KER1: Install new 33kV underground cable from new line to existing Waipapa substation site. Top Energy has proposed a new substation in the Kerikeri area to improve the network capacity and the power quality in the area. The new cable of approximately 0.2 km is planned to be installed from the existing Waipapa substation to the new line in The completed line will connect the proposed substation site to the existing 33kV network via Waipapa substation. 33KV-OH-KAO1: Build new 33kV line from Kaeo Gun Club to Kaeo site. Top Energy has proposed a new substation in the Kaeo area on Martins Road to improve the network capacity and the power quality in the area. The new line of approximately 7.5 km is planned to be built from the Kaeo Gun Club to the new proposed substation site in the year A 33kV line has already been built from the Waipapa substation to the gun club site. The completed line will connect the proposed substation site to the existing 33kV network via Waipapa substation. 33KV-UG-KER2: Construction of KER No 2 33kV line from Wiroa to Hall Rd - Stage 2 The 33kV supply to the new Kerikeri Substation will be by means of two underground 33kV circuits, one from Waipapa, the other from Wiroa. This project is for the Wiroa line and covers the final section from Kerikeri Rd, through Hall Rd, Mill lane and into the substation. Completion will coincide with the commissioning of Kerikeri Substation. Underground is the preferred construction method due to resource consenting constraints on the primary route into Kerikeri. The cable will be 33kV 630mm Al in trifoil configuration, horizontally drilled and installed in continuous ducting. Fibre communications cable will be laid at the same time. 123

126 LIFE CYCLE ASSET MANAGEMENT 33KV-UG-KER1: KER No1 line 3.5 km - WPA Rd to the Sub Site The 33kV supply to Kerikeri Substation will be by means of two underground 33kV circuits, one from Waipapa, the other from Wiroa. This project is for the Waipapa Line. It connects to existing overhead 33kV line on Waipapa Rd, follows Rainbow Falls Rd, crosses the Kerikeri River and then through Fairway Dr, to Nelson St, Cobham Rd and into the substation. The cable will be 33kV 630mm Al in trifoil configuration, horizontally drilled and installed in continuous ducting. Fibre communications cable will be laid at the same time. 33KV-UG-WRR: 33kV Cable installation - Sub to Airport Junction The interconnection of Wiroa substation and Kerikeri substation and the 33kV feeders to Waipapa and Mt Pokaka substations will be by means of cables along Wiroa Rd to the Airport junction - 4 circuits in all. These cables will be 33kV 630mm Al in trifoil configuration, horizontally drilled and installed in continuous ducting. 11kV cable ducts and a fibre cable will be laid at the same time. Overhead construction was considered. However 4 overhead circuits along a busy Wiroa Rd would have been a difficult and expensive proposition and pose needless public safety risk and risk to the Network security. This project is for the the design portion of the work. Completion will coincide with the commissioning of the 33kV switching station. 33KV-OH-KAO1: 33kV - Interconnection with 110/33kV Line Construction of the Kaeo Substation will be commenced in FYE 17. Two 33kV lines will supply it, one from Wiroa adjacent to the new TE kV line and the other as an extension of the China Clay 11kV feeder which is currently 33kV construction. This project is the consenting and design phase of the interconnecting line from the TE2020 dual circuit to the new substation site in Martin Rd. The line will be built overhead on steel poles, cockroach conductor and will extend approximately 7.5 km to the new substation site in Martin Rd. The line is planned to be commissioned at the end of FYE17. This project is for the line design and consenting stages. 110KV-CONNECT-KHE: Kaokohe 110kV interconnection design The new Kaikohe to Wiroa 110kV double circuit line will need to be connected into the Kaikohe 110kV switchyard. This project will undertake design and construction of this interconnection 33KV-OH-WPA1: Decommission WPA 1 33kV line - Kaikohe to SH1 A new double circuit 110kV line is being constructed to supply Kerikeri, Waipapa and the Eastern Bays via Wiroa substation. This is due to be completed at the end of FYE 13, with the 33kV substation to follow in FYE14. Once this is commissioned the need for the Waipapa No 1 33kV line will cease and the line can be decommissioned and removed. The section north of SH1 will be retained as an express 11kV supply to Waimate North. This project is for the removal of the section from Kaikohe substation to SH1 110KV-OH-TPA: 110kV Interconnection Line from Peria to Taipa - 7.5km The existing Taipa substation has one transformer fed from a single 33kV line from Kaitaia. In order to provide n-1 security to Taipa and Mangonui a new 110kV to 11kV substation will be built at the northern end of the Oruru valley. Supply will be via double circuit 110kV line from the new TE kV line at Peria. this project is for the design and construction of this 110kV line. 124

127 LIFE CYCLE ASSET MANAGEMENT 110KV-CONNECT-KHE: Kaitaia 110kV interconnection The new Kaikohe to Wiroa 110kV double circuit line will need to be connected into the Kaikohe 110kV switchyard. This project will undertake design and construction of this interconnection 33KV-UG-WPA/KAO: 33kV - KEO - New UG cable and switch at Waipapa The present China Clays 11kV feeder is built with 33kV construction, and will ultimately become one of the 33kV supplies to the new Kaeo substation. When that takes place the Waipapa substation termination will need to be converted to 33kV with a new circuit breaker bay and a cabled interconnection between the substation and the start of the feeder. This project covers the installation of this interconnection. It is planned to be completed in FYE 15 33KV-MARINE-HAR: Russell Submarine Cable Load growth on the Russell peninsular and poor system reliability, due to fault response difficulties, have triggered the need for an effective Network upgrade for Russell town. Several options have been considered including standby generation, distribution conversion to 22kV, and a submarine from Paihia to Russell. Ultimately all these options will be implemented to some degree as interim solutions. Ultimately however direct supply to Russell via submarine cable will be required. This investment has been deferred as long as possible and currently is planned for completion in FYE This project is for the planning and design phase of a 33kV submarine cable from Paihia to Russell and the installation of a 33kV mini substation in Russell. Supply will be from Haruru substation via the existing Joyces Rd feeder (currently built as a 33kV line but operating at 11kV) to the submarine cable on the Paihia foreshore. An alternative 11kV supply to Paihia is being provided via an 11kV cable from Haruru to Ti Bay to replace the Joyce's Rd supply. 33KV-OH-PUR: Purerua-33kV 8.5km The Purerua Peninsular is expected to develop and grow in electricity demand in a similar fashion to the Eastern Bays. Eventually demand will outstrip the 11kV network's capacity to supply the area. Consequently an alternative higher capacity supply line will be required. At present this planned to be either a 22kV supply from Waipapa or a 33kV supply from Waipapa to a new substation on the Peninsular. These alternatives are still being evaluated and the final choice may be determined by line route constraints and the rate of growth experienced. Completion of the line is planned for This project is for the design and consenting stage of the work to be undertaken in KV-OH-HUP: Pakaraka Hupara 33kV tie line The Southern Area 33kV sub-transmission system incorporating KHE, HAR, KWA and MOE will be reconfigured as a single ring in FYE13 and protection upgraded accordingly. As load grows it will be necessary to reconfigure this ring again into two ring circuits in order for the protection to continue function correctly. This reconfiguring will involve the construction of a tie line between the KAW 1 line to HAR at Pakaraka and KAW 2 along Ludbrook Rd (1.5km) This line construction is planned for FYE KV-OH-WHI: Whatuwhiwhi 33 kv line - 15km The Karikari Peninsular is expected to develop and grow in electricity demand in a similar fashion to the Eastern Bays. Eventually demand will outstrip the 11kV network's capacity to supply the area. Consequently an alternative higher capacity supply line will be required. At present this planned to be either a 22kV supply from Taipa or a 33kV supply from Kaitaia to a new substation at Whatuwhiwhi. These alternatives are still being evaluated and the final choice may be determined by line route constraints and the rate of growth experienced. Completion of the line is planned for

128 LIFE CYCLE ASSET MANAGEMENT 33KV-OH-OMA: New 33kV line to Omanaia substation. Omanaia is currently supplied by a single 33kV line and hence has n security. The existing line is prone to outages due to trees and other issues and hence reliability and security of supply for the Hokianga area is inadequate. It is planned to construct an additional 33kV circuit from Kaikohe to Omanaia commencing FYE 2021 to rectify this situation. This project is for the final stage of construction to be undertaken in kV/33kV and 33kV/11kV Substations PROJECT NO. DETAILS DRIVER FYE START BUDGETE D COST K$ SUB- CONTRACT- KER-2013 Substation Construction - Civil, building, cabling, equipment, transformer 1 and 2 EX SUB- OH-NPL Church Rd Interconnection EX SUB-DESIGN- WRR-2013 SUB- VARIOUS- WPA-2013 Switching station Wiroa - temp Kerikeri Connection and Substation design EX Substation Protection and minor project completion RS SUB-HAR-TiBay Ti Bay cable installation Into Substation RS SUB- REC-OKH Line recloser and protection install RS SUB-LAND-TPA kV / 11 kv substation at Taipa - land EX SUB- BLG/SWCH- WRR-2014 SUB-DESIGN- TPA-2015 Switching station Wiroa - Building and 33kV Indoor switchboard install EX kV / 11 kv substation at Taipa - Concept Design & consents EX Moerewa 33kV outdoor to indoor conversion Design - Stage 1 Conversion RS SUB- DESIGN- MOE-2015 SUB-CIVIL-WRR kV Substation Wiroa - 110kV Civils EX SUBS- SECURITY Security systems for substations - stage 1 RS

129 LIFE CYCLE ASSET MANAGEMENT SUB-DESIGN- TPA kV / 11 kv substation at Taipa - Final Design EX SUB- DESIGN- KAO-2016 SUB- INDOOR- MOE-2016 SUB-TF1-WRR SUB - KAEO - New substation at Kaeo. Design and Planning EX Moerewa 33kV outdoor to indoor conversion Stage 2 RS kV Substation Wiroa - 110kV Transformers Transformer 1 EX SUB-SWTCH- WRR kV Substation Wiroa - 110kV Switchgear EX SUB-TF2-WRR kV Substation Wiroa - 110kV Transformers Transformer 2 EX SUBS- SECURITY Security systems for substations - stage 2 RS SUB- DESIGN- WPA-2017 SUB - WPA - Substation rebuild design RS SUB- RIPPLE- WRR-2017 New Ripple injection plant Wiroa EX SUB- CIVIL- KAO-2017 SUB- SWTCHGR-KAO SUB- SWTCHGR-KAO PROT-FDR- KWA-2017 PROT-TF-KWA KAEO - New substation at Kaeo. Civil, building, etc - Turnkey EX KAEO - New substation at Kaeo. 11kV Switchgear and protection EX KAEO - New substation at Kaeo. 33 kv Switchgear and protection EX SUB - KWA - Feeder protection upgrade 4 x SEL 351S, in new boxes on CBS, SEL2032.GPS clock. RS SUB - KWA - Transformer protection upgrade,sel 387E, Reg D, 1 A NCT, GPS Clock, RS SUB Sub - KWA - Lower Transformers to ground level and bunding RS SUB- TF-KAO- SUB- TF-MOE Moerewa TF 1 - New New TF 15/23 MVA RS SUB- TF-MOE Moerewa TF 2 - New New TF 15/23 MVA RS DESIGN- Substation and Line design EX

130 LIFE CYCLE ASSET MANAGEMENT WHI-2017 SUB- DESIGN- PUR-2017 Purerua Substation design EX SUB-TPA kV / 11 kv substation at Taipa stage 1 EX SUB- SWTCHGR-KHE Kaikohe 11kV Changeover - new switchboard RS SUB TF-WPA- SUB - WPA - Lower transformers to ground level and bunding RS SUB- SWTCH/BLDG- WPA-2018 SUB - WPA - Indoor Switchgear and building RS PROT-FDR- OMA-2018 T1 Transformer Protection Upgrade RS SUB-TPA kV / 11 kv substation at Taipa stage 2 EX SUB- OH-HUP Hupara interconnections RS SUB- TF-KAO SUB - KAEO - New substation at Kaeo Transfomers EX SUB- LAND- PUR-2018 SUB - New ZS Golf Course location-purerua- Easements LAND EX SUB-WRR- 11kVSwGr-2018 Substation Wiroa - 11 kv Switchgear EX SUB-TPA kV / 11 kv substation at Taipa stage 3 EX kV-UG-WRR Fdrs-2019 Substation Wiroa - 11 kv interconnections EX SUB- TF-OMA SUB - OMA - install 6.25MVA ex Taipa with CB EX SUBS-PROT- PUR-2020 Purerua-Protection RS SUB- CIVIL-PUR Purerua-Substation Building and Civils - Turnkey EX SUB- SWTCHGR-PUR Purerua Sub - 11kV Switchboard EX SUB- Purerua Sub- 36kV Tx Panel EX

131 LIFE CYCLE ASSET MANAGEMENT SWTCHGR-PUR Purerua--Construction of 100 m of 3c 300 mm2 Al XLPE EX SUB- CABLE- PUR-2020 Purerua-3 x 100m 3c 185mm2 Al XLPE Incomers EX SUB- CABLE- PUR-2020 SUB- CIVIL- WHI-2020 Civil Works for Substation, building etc EX SUB- SWTCHGR-WHI Switchgear and Comms EX PROT-METER- OKH-2021 OKH - Feeder metering, 6 x SEL 734 in to existing feeder panels RS SUB- TF-PUR SUB - Purerua - New 5/9 MVA transformer EX SUB- TF-WHI Transformer EX SUB- SWTCHGR- KAW kV Switchboard Replacement - new building RS Figure 92: Transmission and Subtransmission substation projects Wiroa 33kV Switching Station Top Energy s new 33kV Switching station / is situated some 25km from the Kaikohe GXP and will supply power to the Waipapa and proposed Kerikeri, Kaeo, and Purerua substations. Provision will be made for it to eventually be upgraded to a 110/33 kv substation. a) Demand As this will be a 33kV switching station for the first 25 years of operational life, detailed demand profiles have not yet been determined, however it is expected that the decision to upgrade to 110kV will be as a result of capacity maximum being reached on the Kaikohe Wiroa 33kV circuits. b) Security The substation will eventually have two transformers and a single 110kV bus, served by a double circuit 110kV line from Kaikohe. The line will be constructed of Selenium conductor to facilitate a high capacity 33kV link, thus deferring the investment in the 110kV substation plant until beyond c) Capacity The substation, upon upgrade is planned to have a firm capacity of 50 MVA and a switched capacity of 50 MVA, although this will be subject to review as the development timeframe progresses. The proposed capacity will be sufficient to supply the forecasted load for the region until beyond

132 LIFE CYCLE ASSET MANAGEMENT d) Substation Projects PROJECT NO. DETAILS DRIVER FYE START BUDGETED COST SUB-DESIGN- WRR-2013 Switching station Wiroa - 33kV Indoor switchboard and Substation design K$ Capacity Capacity 33KV-UG- WRR kV Cable installation - Sub to A/P Junction SUB- BLG/SWCH- WRR-2014 Switching station Wiroa - Building and 33kV Indoor switchboard install Capacity SUB-CIVIL- WRR kV Substation Wiroa - 110kV Civils Capacity SUB-TF1- WRR-2016 SUB-SWTCH- WRR-2016 SUB-TF2- WRR-2016 Figure 93: 110kV Substation Wiroa - 110kV Transformers Transformer 1 110kV Substation Wiroa - 110kV Switchgear 110kV Substation Wiroa - 110kV Transformers Transformer 2 Wiroa substation projects Capacity Capacity Capacity SUB-DESIGN-WRR, SUB-BLG/SWCH-WRR: Switching station Wiroa - Building and 33kV Indoor switchboard install In order to supply Kerikeri and Waipapa at 33kV with sufficient capacity for present and future needs a new 110kV to 33kV substation will be constructed at Wiroa. Initially and until the new TE kV line is complete from Kaikohe to Kaitaia, supply to Waipapa and Kerikeri will made at 33kV via the double circuit line from Kaikohe to Wiroa. As an interim measure, the 33kV indoor switchboard and building will be constructed to facilitate this supply. This project is for the construction of the building and installation of the 33kV switchgear at Wiroa substation. SUB-CIVIL-WRR, SUB-SWTCH-WRR, SUB-TF1&2-WRR: 110kV Substation at Wiroa In order to supply Kerikeri and Waipapa at 33kV with sufficient capacity for present and future needs a new 110kV to 33kV substation will be constructed at Wiroa. Initially and until the new TE kV line is complete from Kaikohe to Kaitaia, supply to Waipapa and Kerikeri will made at 33kV via the double circuit line from Kaikohe to Wiroa. As an interim measure, the 33kV indoor switchboard and building will be constructed to facilitate this supply. This project is for the construction of the building and installation of the 110kV switchgear and transformers at Wiroa substation. 130

133 Okahu Substation. LIFE CYCLE ASSET MANAGEMENT Top Energy s Okahu Road substation is situated some 5km from the Kaitaia GXP and supplies power to the Kaitaia town and rural districts as far south as the Hokianga harbour. e) Demand The present peak demand at Okahu Road substation is 10.3 MVA. Long term forecasted load growth is 1.8% pa. The load in year 2021 is forecasted to be 11.7 MVA. f) Capacity The existing two 11.5 MVA transformers are adequate to supply the forecasted load for the planning period. g) Security The substation has two transformers, single 33kV bus, served by a double circuit 33kV line. The substation has a firm capacity of 15.2 MVA including a switched transfer capability of 3.7 MVA. The substation requires a security level of 3 for the planning period but the substation has the same security issue as the NPL substation with incoming 33kV double circuit line, which is described in the sub-transmission section. h) Substation Projects PROJECT NO. DETAILS DRIVER START YEAR BUDGETED COST SUBS-SECURITY SUB - OKH - Install new Security System K$ Reliability PROT-METER-OKH-2021 SUB - OKH - Feeder metering, install new SEL 734 x 6 into existing feeder panels Reliability Figure 94: Okahu Rd substation projects SUBS-SECURITY1-2015: New security system. The project is to install electronic security systems including two security cameras in the substation building to give added safety and security in the year 2015 PROT-METER-OKH-2021: New feeder protection relays. The project to install six new SEL734 protection relays in the existing panels to give better metering and fault information for planning and fault analyse in the year Pukenui Substation Top Energy s Pukenui substation is located an hour s drive north of Kaitaia in the small coastal township of Pukenui. The area is sparsely populated and has a number of holiday homes which drives the seasonal demand at this substation. There have been a number of subdivisions over the last two years in the region and this trend is set to continue with an increased demand for lifestyle holiday homes. 131

134 LIFE CYCLE ASSET MANAGEMENT a) Demand The present peak demand at Pukenui substation is 1.9 MVA. Long term forecasted load growth is 4.1 % pa. b) Capacity A single 5 MVA transformer, upgradeable to 6.25 MVA is adequate for the planning period. c) Security The substation has one transformer, a single 33kV bus, supplied by a single 33kV circuit from the northern GXP. The substation has no firm capacity as it has only a single transformer bank and very little switched capacity, 0.24 MVA. The substation has a Top Energy security level of 1 and meets that requirement. While there is only one sub-transmission circuit supplying the substation, redundancy is provided through the 11kV feeders. This is achieved by utilising Top Energy s Awanui feeder with 2 sets of voltage regulators to maintain supply through to Cape Reinga. The switched capacity of 0.24 MVA can be provided through the 11kV feeders. It should be noted that the 11kV feeder backup is dependent upon the voltage regulators being in service. This substation meets the Top Energy Security of Supply Standard, although due to the distances involved there are growing concerns about the quality of the delivered supply under these back up conditions. Those concerns, along with the sensitivity of the back up provision to quite small increments in load, have resulted in the decision to carry out any construction at 22kV rather than 11kV in preparation for a possible future upgrade should significant load growth occur. d) Substation Projects PROJECT NO. DETAILS DRIVER START YEAR BUDGETED COST SUBS-SECURITY SUB - PKN - Install new Security System Reliability K$ Figure 95: Pukenui substation projects SUBS-SECURITY : New security system. The project to install electronic security systems, including two security cameras, in the substation building, to give added security in the year Taipa Substation Top Energy s Taipa substation is located some 55km from the Kaitaia GXP on the east coast. This substation supplies the Taipa and Mangonui areas. The existing zone substation at Taipa consists of a single 5/6.25MVA transformer and is supplied by a single incoming 33kV circuit from the Kaitaia transmission substation. The peak demand is already approaching the natural cooling capacity of the transformer and the level at which Top Energy s security criteria requires an N-1 supply to be available. The 11kV transfer capacity into the area is limited. As noted in Section 5.7.2, Top Energy has now installed 5MVA of diesel generation at the site, which will provide some backup in the event of a loss of supply, but is not a long term solution. Top Energy s original network development plan envisaged upgrading the substation to a dual 11/23MVA facility and constructing a new 33kV circuit between Kaeo and Taipa, to provide a backup incoming supply. However, the construction of the new 110kV circuit between Wiroa and Kaitaia has opened up new possibilities. 132

135 LIFE CYCLE ASSET MANAGEMENT One possibility is to construct a second 33kV circuit from Kaitaia, with the circuit being underbuilt on the new 110kV line over part of its route. A second option is to divert the 110kV circuit to a point closer to Taipa and to build a 110/11kV substation on a new site. The new substation would use zigzag transformers to ensure that the 11kV phasing was the same as the rest of the network. More economic analysis is needed to determine the most cost-effective option, although the 110/11kV substation currently looks promising. This work is planned for completion by FYE 2019 and further analysis of the proposed project will be presented in next year s asset management plan.. The existing Taipa transformer will then be relocated to Omanaia and replace the existing 2.75MVA transformer bank. Demand The present peak demand at Taipa substation is 5.3 MVA. Long term growth is forecasted to be 4.4% pa. The load in 2021 is forecasted to be 6.6 MVA. a) Capacity The existing 6.25MVA transformer is adequate to supply the load until Beyond that, increased capacity will be required to mitigate the forecasted load on the substation. The replacement of the existing single 6.25 MVA transformer with 2 x 11.5/23 MVA units is currently planned in year 20014/15. b) Security The substation has one transformer, a single 33kV bus, served by a single circuit 33kV line. The substation has no firm capacity as it has only a single transformer bank and very little switched capacity, 0.32 MVA. With the present supply arrangements, the substation does not meet the Top Energy Security of Supply Standard. In order to provide n-1 security to Taipa and Mangonui a new 110kV to 11kV substation will be built at the northern end of the Oruru valley. Supply will be via double circuit 110kV line from the new TE kV line at Peria. This project is for the design and construction of the new substation c) Substation Projects PROJECT NO. DETAILS DRIVER START YEAR BUDGETED COST SUB-LAND-TPA kV / 11 kv substation at Taipa - land EX K$ SUB-DESIGN-TPA-2015 SUB-DESIGN-TPA kV / 11 kv substation at Taipa - Concept Design & consents EX kV / 11 kv substation at Taipa - Final Design EX SUB-TPA kV / 11 kv substation at Taipa stage 1 EX SUB-TPA kV / 11 kv substation at Taipa stage 2 EX SUB-TPA kV / 11 kv substation at Taipa stage 3 EX Figure 96: Taipa substation projects 133

136 LIFE CYCLE ASSET MANAGEMENT SUB-LAND-TPA-2014, SUB-DESIGN-TPA-2015, SUB-TPA: These projects are for the design and construction of a new 110kV to 11kV substation at Taipa, including the 11kV interconnections into the adjacent network. The substation will be outdoor 11kV using compact switchgear, dual transformers and an 11kv indoor switchboard Northern Pulp Substation (NPL) Top Energy s Northern Pulp substation is situated some 10km from the Kaitaia GXP and supplies Top Energy s largest customer, Juken Nissho Limited, who operate a wood processing plant. Approximately 75% of the demand at the site can be attributed to Juken Nissho Limited and the balance is fed out into Top Energy s distribution network. a) Demand The present peak demand at NPL substation is 9.7 MVA and is forecast to increase to 12.5 MVA by 2021 as a result of load transfers. Currently, this substation primarily supplies one major industrial customer and load growth tends to be driven by specific plant installation projects rather than reflecting a general growth pattern. However, Juken Nissho has indicated that demand growth at its site over the planning period is unlikely. Top Energy is therefore planning to increasingly use this substation to supply other consumers in the surrounding area. b) Capacity The substation has two transformers with ratings of 23 MVA for T1 and 11.5MVA for T2. T2 can be uprated to 23MVA by improving the cooling arrangements. c) Security The substation has two transformers, a single 33kV bus, and is fed by a double circuit 33kV overhead line. The substation has firm capacity of 12.6 MVA and switched capacity of 1.1 MVA. The substation has the security level requirement of 4. It means that under the Top Energy security of supply standard the full load of the substation should remain uninterrupted in the event of a single outage. Arguably the substation meets the requirement with two 33kV circuits. However the double circuit single pole 33kV line from Transpower Kaitaia is an area of concern in terms of the security of supply because a single pole failure could result in loss of supply. With this in mind a project has been planned to improve the security of supply at 33kV sub-transmission level and is described in the subtransmission line project section. d) Substation Projects PROJECT NO. DETAILS DRIVER START YEAR BUDGETED COST SUBS-SECURITY SUB - NPL - Install Security Cameras Reliability Figure 97: NPL substation projects SUBS-SECURITY1-2015: New security system. The project is to install electronic security systems including two security cameras in the substation building to give added security in the year 2015 k$ Kaikohe (Top Energy) Substation Top Energy s Kaikohe substation is located adjacent to the Kaikohe GXP and supplies the major town of Kaikohe, and the townships of Ohaeawai and Okaihau. There has been little or no economic growth in 134

137 LIFE CYCLE ASSET MANAGEMENT Kaikohe for some time and the only significant recent development has been the new Ngawha prison which contributed 570kVA to the load. a) Demand The present peak demand at Kaikohe substation is 10.4 MVA. Long term forecasted load growth is 1.7% pa. b) Capacity The substation consists of two 11.5 MVA transformers upgradeable to 23MVA. This is adequate for the planning period. c) Security The substation has two transformers, a single 33kV bus, served by a 33kV circuit from the adjacent Transpower substation. The substation has a firm capacity of 12.5 MVA and a switched capacity of 1.0 MVA. The substation requires a security level of 3 and the Top Energy security of supply standard is fully met for the planning period. d) Substation Projects PROJECT NO. DETAILS DRIVER START YEAR BUDGETED COST SUBS-SECURITY SUB - KHE - Install new Security System K$ Reliability SUB-SWGR-KHE-2014 Kaikohe GXP 33kV Switchgear, Building and transformer shift Reliability Figure 98: Kaikohe substation projects SUBS-SECURITY2-2016: New security System. The project to install electronic security systems including two security cameras in the substation building to give added security in the year 2016 SUB-SWGR-KHE-2014: New 33kV Switchgear at GXP Kaikohe GXP 33kV switchyard is in poor condition and near end of life. In addition, the 33kV transformers in the Kaikohe zone substation are elevated on plinths, an inherent earthquake risk. This project will replace the outdoor switchyard and equipment with an indoor switchboard in a new building, and relocate the transformers from their present locations onto ground level pads adjacent to the new switchroom. In addition, outstanding projects for the upgrading of protection, and bunding of the transformer bays for oil spillage containment will occur as part of this project work. SUB- SWTCHGR-KHE-2018: Kaikohe 11kV Changeover - new switchboard The Kaikohe 33kV switchyard will be relocated indoors in a new switch-room in FYE14. The existing 11kV board will remain in its present location until FYE18 to maximise its lifespan. At that stage a new 11kV switchboard will be installed in the new switch--room along with the 33kV equipment and the old 11kV gear decommissioned and removed. This project is for the procurement and installation of the new equipment and the removal of the old in FYE18 135

138 Kawakawa Substation LIFE CYCLE ASSET MANAGEMENT Top Energy s Kawakawa substation is located some 33km from the Kaikohe GXP and feeds the major townships of Kawakawa, Opua and Russell. There has been considerable growth in Russell and Opua driven by demand for lifestyle property and the marina development at Opua. a) Demand The present peak demand at Kawakawa substation is 5.7 MVA. Once the new planned cable to Russell is provided, Kawakawa substation would be unloaded. b) Capacity The substation consists of two 5 MVA transformers which is sufficient to supply the forecasted load during the planning period. c) Security The substation has two transformers, a single split 33kV bus, served by two 33kV circuits. The substation has the firm capacity of 7.5 MVA and switched capacity of 2.5 MVA at present. The substation presently exceeds the required security level of 2. d) Substation Projects PROJECT NO. DETAILS DRIVER START YEAR BUDGETED COST K$ SUBS-SECURITY SUB- TF-KWA-2017 PROT-FDR-KWA-2017 SUB - KWA - Install new Security System Sub - KWA - Lower Transformers to ground level and bunding KWA - Feeder protection upgrad Reliability Reliability / Security Reliability PROT-TF-KWA-2017 KWA - Transformer protection upgrade SUB- SWTCHGR-KWA kV Switchboard Replacement - new building. Reliability Reliability Figure 99: Kawakawa substation projects SUBS-SECURITY2-2016: New security system. The project is to install electronic security systems including two security cameras in the substation building to give added security in the year 2016 SUB- TF-KWA-2017: New transformer bunding. Kawakawa substation indoor equipment is nearing the end of it's service life, and the transformers are still on raised plinths posing a significant earthquake risk. Replacement is planned before accelerated 136

139 LIFE CYCLE ASSET MANAGEMENT maintenance is required or equipment failure is experienced. The transformer will be shifted onto new ground level pads. This project is for the transformer relocation stage of the project to be undertaken in FYE 17 PROT-FDR-KWA-2017: Feeder Protection Upgrade Feeder protection upgrade 4 x SEL 351S, in new boxes on CBS, SEL2032.GPS clock. PROT-TF-KWA-2017: Transformer Protection Upgrade Transformer protection upgrade,sel 387E, Reg D, 1 A NCT, GPS Clock, SUB- SWTCHGR-KWA-2022: 11kV Switchboard Replacement - new building Kawakawa substation indoor equipment is nearing the end of it's service life. Replacement is planned before accelerated maintenance is required or equipment failure is experienced. The existing indoor 11kV switchgear will be replaced with further indoor equipment. This project is for the switchgear replacement stage of the project to be undertaken in FYE 22. As part of this project other outstanding work such as feeder and transformer protection upgrades will be undertaken Moerewa Substation Moerewa substation is located some 30km from the Kaikohe GXP and predominantly supplies AFFCO meat works. The load at this substation has been relatively constant for years as there has been very little expansion of the meat works. a) Demand The present peak demand at Moerewa substation is 3.8 MVA. Long term forecasted load growth is 0.5% pa. b) Capacity The existing 11.5 MVA transformer is in excess of the required capacity at the substation. While not included in this Development Plan, there is some possibility of a new dairy factory being built alongside the meat works, and at this stage there are no plans to relocate this transformer during the planning period. c) Security The substation has one transformer, a single 33kV bus, and is served by two 33kV circuits on separate routes. The substation does not have any permanent firm capacity because of only one transformer at present, but has 2.10MVA of switchable transfer capacity. The substation should have a security level of 2 for the planning period. In the event of transformer failure, the substation would not be able to meet the required security of supply as the present 11kV transfer capacity is not adequate to restore the required level of supply. However the mobile substation is currently relocated at the substation to provide n-1 security. d) Substation Projects Moerewa substation outdoor equipment is nearing the end of its service life. This is in part due to the corrosive atmosphere at the substation. Replacement is planned before accelerated maintenance is required or equipment failure is experienced. It has been determined that the most cost effective solution for the replacement is to rebuild the substation indoors, in a new switchroom, containing both 11kV and 33kV switchgear plus control and protection equipment. 137

140 LIFE CYCLE ASSET MANAGEMENT PROJECT NO. DETAILS DRIVER START YEAR BUDGETE D COST SUBS- SECURITY SUB-DESIGN- MOE-2015 SUB-INDOOR- MOE-2016 SUB - MOE - Install new Security System Moerewa 33kV outdoor to indoor conversion Design and Stage 1 Moerewa 33kV outdoor to indoor conversion Stage 2 K$ Reliability Reliability Reliability SUB TF-MOE- Moerewa TF - New New TF 15/23 MVA Reliability Figure 100: Moerewa substation projects SUBS-SECURITY2-2016: New security system. The project is to install electronic security systems including two security cameras in the substation building to give added security in the year SUB-INDOOR-MOE: Moerewa 33kV outdoor to indoor conversion This project is for the design, purchase and installation of new inddor switchgear in a new building. It is to be undertaken in FYE 15 and 16. This project will also incorporate outstanding project work such as the upgrading of feeder protection relays. SUB- TF-MOE-2017: Moerewa New Transformers 15/23 MVA This project is for the purchase and installation of two new transformers which will provide full n-1 security. The existing transformer will be refurbished and set aside as a network spare This project is for the procurement and installation of both 15/23MVA transformers to be undertaken in FYE 17. Other outstanding projects such as the oil containment bunding of the transformers will be undertaken as part of this project Haruru Falls Substation Top Energy s Haruru Falls substation is located some 35km from the Kaikohe GXP and supplies the town of Paihia and the township of Haruru Falls. The load at this substation has been growing significantly due to developments in Paihia and Haruru Falls. a) Demand The present peak demand at Haruru substation is 6.8 MVA. Long term forecasted load growth is 5.1% pa. 138

141 LIFE CYCLE ASSET MANAGEMENT b) Capacity c) Security The substation has two transformers. each rated at 23MVA, which are adequate to supply the forecasted load for the planning period. The substation has two transformers, a single 33kV bus, served by two 33kV circuits from the Transpower substation. The substation has a firm capacity of 23.0 MVA and a switchable transfer capacity of 1.0 MVA. The substation requires a security level of 3 and the Top Energy security of supply Standard is fully met for the planning period. d) Substation Projects PROJECT NO. DETAILS DRIVER START YEAR BUDGETED COST SUBS-SECURITY Sub - HAR - install new security system K$ Reliability Figure 101: Haruru Falls substation projects SUBS-SECURITY2-2016: New security system. The project is to install electronic security systems including two security cameras in the substation building to give added security in the year Waipapa Substation Top Energy s Waipapa substation is located some 33km from the Kaikohe GXP and supplies the town of Kerikeri and townships of Waipapa and Kaeo. The load at this substation has been growing rapidly over the last 4 to 5 years, reflecting increased demand for lifestyle properties in the Kerikeri region. a) Demand The present peak demand at Waipapa substation is 20.8 MVA. Long term forecasted load growth is 7.7% pa. Approximately 8 MVA of load will be shifted to the proposed Kerikeri substation in the year Approximately 4 MVA of load will be shifted to the proposed Kaeo substation in the year 2017 and approximately 6 MVA of load will be shifted to the proposed Purerua substation in the year The shifts in load to these three substations are reflected in the forecasted load of Waipapa substation, which is expected to reduce to 13.6 MVA by b) Capacity The substation has two 11.5/23MVA transformers that are sufficient to supply forecasted load for the planning period. c) Security The substation has two transformers, a single split 33kV bus and is supplied by two separate incoming 33kV circuits. The substation has the firm capacity of 15.4 MVA and the switched capacity of 0.73 MVA, although this will reduce significantly once Kerikeri Substation is commissioned in 2013 This substation should ideally be a level 4 under the Top Energy security of supply Standard and the basic sub-transmission components meet the requirements for this class of supply. However, it is not presently possible under all contingent configurations to supply the peak load of the substation. 139

142 LIFE CYCLE ASSET MANAGEMENT Depending on circumstances, constraints can appear due to voltage drop issues, the rating of the incomer 11kV circuit breakers and the settings possible on the protection relays. d) Substation Projects PROJECT NO. DETAILS DRIVER START YEAR BUDGETED COST K$ SUB- VARIOUS-WPA-2013 Substation Protection and equipment upgrades Reliability SUBS-SECURITY SUB - WPA - Install new Security System Reliability SUB- TF-WPA-2018 SUB - WPA - Lower transformers to ground level and bunding Compliance SUB- SWTCH/BLDG-WPA-2018 WPA Indoor Switchgear and Building Reliability Figure 102: Waipapa substation projects SUB- VARIOUS-WPA-2013: Substation Protection Upgrades Substation audits have revealed that protection equipment at Waipapa Sub are substandard and need to be brought up to standard. This project addresses these issues. SUBS-SECURITY2-2016: New security system. The project is to install electronic security systems including two security cameras in the substation building to give added security in the year SUB- TF-WPA-2018: New transformer bunding. To improve earthquake resistance and to provide oil containment for any oil spillage from zone substation transformer, it is planned to lower the transformer from its structure for bunding in the year 2018 SUB- SWTCH/BLDG-WPA-2018: WPA Indoor Switchgear and Building Waipapa substation outdoor equipment is nearing the end of its service life, the substation yard is becoming congested and working clearances are tight. Replacement is planned before accelerated maintenance is required or equipment failure is experienced. It has been determined that the most cost effective solution for the replacement is to rebuild the substation indoors, in a new switchroom, containing both 11kV and 33kV switchgear plus control and protection equipment. The transformer will be shifted onto a new ground level pads. This project is for the new building and switchgear stage of the project to be undertaken in FYE

143 Omanaia Substation LIFE CYCLE ASSET MANAGEMENT Top Energy s Omanaia substation is located some 50km west of the southern GXP and basically feeds the south west coast of Top Energy s geographic area. a) Demand The present peak demand at Omanaia substation is 2.4 MVA. Long term forecast load growth is 1.7% pa. b) Capacity The substation has a single bank 2.75MVA transformer capacity. The bank is expected to reach the end of its service life by At that time, the existing Taipa 6.25MVA transformer is planned to be relocated to the Omanaia substation. c) Security The substation has a single bank transformer facility, single bus configuration, served by one incoming 33kV circuit. The substation has the firm capacity of 0.0 MVA and the switched capacity of 0.3 MVA. The substation has the security level of 1 which requires supply to be restored only after replacement or repair of faulty equipment. Because of the distances involved in locating and repairing faults on the 33kV line, a project is planned to improve 11kV interconnection and therefore, the load transfer capability from the Kaikohe substation in year 2011/12. This will allow partial restoration in the event of a transformer failure reducing the impact on customers while the mobile substation is relocated. d) Substation Projects PROJECT NO. DETAILS DRIVER START YEAR BUDGETED COST SUBS-SECURITY PROT-TF-OMA-2018 SUB- TF-OMA-2019 SUB - OMA - Install new Security System SUB - OMA - Transformer T1 Protection upgrade, SEL 387E, New NCT 1A, Existing Circuit Breakers ok. SUB - OMA - install 5/6.25MVA ex TPA K$ Reliability Reliability / Security Capacity Figure 103: Omania substation projects SUBS-SECURITY2-2016: New security system. The project is to install electronic security systems including two security cameras in the substation building to give added security in the year 2016 SUB- TF-OMA-2019: Install 5/6.25MVA TX ex Taipa Following the replacement of the Taipa transformer in 2015, the removed unit will be installed within the Omanaia substation as an additional unit in this location. This will provide N-1 security of supply 141

144 LIFE CYCLE ASSET MANAGEMENT over the transformers in 2016 and over the entire substation following the 33kV Omanaia #2 feeder construction in PROT-TF-OMA-2018: Transformer Protection Upgrade Existing transformer protection is not up to standard and needs replacing. The new protection will be in line with the protection standard and utilise SEL relays Proposed Kaeo Substation Supply to the coastal belt north of Waipapa, as well as the inland rural area to the North West, is becoming increasingly difficult. The area served is large and development of the coastal strip between Matauri Bay and Whangaroa is becoming increasingly more intensive. Immery s Tableware, located in this region near Matauri Bay is currently served from Waipapa by a long, heavily-loaded rural feeder. A portion of this line between Waipapa and the Kaeo Gun Club on State Highway 10 is constructed at 33kV and operated at 11kV. Top Energy has purchased land for a new 33kV zone substation on Martins Rd in the Kaeo area. The new substation will be supplied by two incoming 33kV circuits. One line will be supplied from Waipapa and will be an extension of the existing 33kV line from the Kaeo Gun Club. The second circuit will be a new circuit from Wiroa, which will be underbuilt on the Wiroa-Kaitaia 110kV line for much of its route. Construction of the incoming 33kV circuits is planned to start in FYE 2014 and construction of the substation is planned for completion in FYE 2018.The new substation will provide several benefits including, - a) Demand Provision of capacity and maintenance of statutory voltage to the increasing demand in the area, Unloading of Waipapa Substation (11kV feeders), Increased security to the Waipapa substation, Potential for support to the Taipa substation. The peak demand in the year 2017/18 is forecasted to be approximately 4 MVA and this is expected to increase to around 4.6 MVA by b) Capacity The substation will have one 11.5 MVA transformer that is sufficient to supply the forecasted load on the substation for the planning period. c) Security The substation will have one transformer, a single 33kV bus and will be supplied by a single circuit 33kV line via the Waipapa substation and a second single circuit feed from Taipa. Further study is required to finalise the value of the firm and switched capacity of the substation. Provision will be made to connect the mobile substation. The security level of 2 is assigned to the substation for the planning period under the Top Energy Security of Supply Standard. 142

145 LIFE CYCLE ASSET MANAGEMENT d) Substation Projects PROJECT NO. DETAILS DRIVER START YEAR BUDGETED COST 11kV-UG-Kauri-2013 Cable overlay at Kauri Cliffs RS K$ 11kV-REC-KAO KV-UG-WPA/KAO KV-OH-WPA/KAO-2016 SUB- DESIGN-KAO-2016 Open point between Rangiahua, Xroads and Totara North Feeders (replace 289 with Entec) RS kV - KEO - New UG cable and switch at Waipapa EX kV - KEO - Upgrade line ABS to volt 800 amp. EX SUB - KAEO - New substation at Kaeo. Design and Planning EX SUB- CIVIL-KAO-2017 KAEO - Civil, building, etc - Turnkey EX SUB- SWTCHGR-KAO-2017 KAEO - 11kV Switchgear and protection EX SUB- SWTCHGR-KAO-2017 KAEO - 33 kv Switchgear and protection EX kV-UG-KAO-2018 Kaeo - 5 x new feeder out of substation EX SUB- TF-KAO-2018 New substation at Kaeo Transfomers EX Figure 104: Proposed Kaeo substation projects 33KV-OH-KAO: 33kV Build new line from gun club to Kaeo site. Construction of the Kaeo Substation will be commenced in FYE 17. Two 33kV lines will supply it, one from Wiroa adjacent to the new TE kV line and the other as an extension of the China Clay 11kV feeder which is currently 33kV construction. This project is the consenting and design phase of the line extension. The line will be built overhead on steel poles, cockroach conductor and will extend approximately Z km to the new substation site in Martin Rd. The line is planned to be commissioned at the end of FYE15. 33KV-UG-WPA/KAO-2015: 33kV - KEO - New UG cable and switch at Waipapa The present China Clays 11kV feeder is built with 33kV construction, and will ultimately become one of the 33kV supplies to the new Kaeo substation. When that takes place the Waipapa substation termination will need to be converted to 33kV with a new circuit breaker bay and a cabled interconnection between the substation and the start of the feeder. This project covers the installation of this interconnection. It is planned to be completed in FYE

146 LIFE CYCLE ASSET MANAGEMENT SUB- DESIGN-KAO-2016, SUB- CIVIL-KAO-2017, SUB- SWTCHGR-KAO-2017: New Kaeo Substation Design and Construction Construction of the Kaeo Substation will commence in FYE 17. Two 33kV lines will supply it, one from Wiroa adjacent to the new TE kV line and the other as an extension of the China Clay 11kV feeder which is currently 33kV construction. 11kV feeders from the substation will supply the town and the surrounding district relieving the demand on existing feeders out of Waipapa. The substation will be built as a turnkey project. Equipment supply will be free issue from Network. These projects cover the design and construction of the substation Proposed Kerikeri Substation Supply to Kerikeri, one of the fastest growing areas in the country, is reliant on two heavily loaded 11kV feeders supplied from the Waipapa zone substation, this situation is rapidly becoming untenable for a town of this size. In the event of the loss of one of these feeders, it would not be possible to maintain supply to all customers, particularly if the loss was to occur at a time of peak load. Some support is now available from Mt Pokaka Timber Products, but this is limited. Top Energy has purchased a site for a new zone substation within the industrial part of the Kerikeri urban area. In 2009, construction of a new overhead 33kV circuit between Waipapa and the outskirts of the town was completed, this circuit will be extended to the new substation site with underground cable. Construction of a second underground 33kV circuit between Wiroa and the new substation site is nearing completion. Construction of the new substation, which will have two 15/23MVA transformers has commenced and is currently programmed for completion in FYE The new substation will provide several benefits including, - a) Demand Provision of capacity and maintenance of statutory voltage to the increasing demand in the area, Unloading of Waipapa Substation (11kV feeders), Increased security for the Waipapa substation, Potential for support to the Waipapa substation. The peak demand in the year 2015/16 is forecasted to be approximately 8 MVA and this is forecast to increase to 9.7 MVA by b) Capacity The substation will have two 11.5/23 MVA transformers that are sufficient to supply the forecasted load on the substation for the planning period. c) Security The substation will have two transformers, a single 33kV bus and will be supplied by two single circuit 33kV line, one from the Waipapa substation and the second from the new Wiroa switching station. Further study is required to finalise the value of the firm and switched capacity of the substation. The security level of 2 is assigned to the substation for the planning period under the Top Energy Security of supply standard. 144

147 LIFE CYCLE ASSET MANAGEMENT d) Substation Projects PROJECT NO. DETAILS DRIVER START YEAR BUDGETED COST K$ SUB-CONTRACT-KER-2013 Substation Construction - Civil, building, cabling, equipment, transformer 1 and 2 EX Figure 105: Proposed Kerikeri substation projects SUB-CONTRACT-KER-2013: Substation Construction - Civil, building, cabling, equipment, transformers A new substation to be constructed in Kerikeri is the result of consistent load growth in the Kerikeri area and the requirement for improved security for the town. It will be supplied from both Wiroa and Waipapa substations via 630mm 33kV cable. The substation will feature 2 x 15/23MVA transformers, and indoor switchgear. The construction of the substation will be undertaken by Turnkey contract. Equipment such as transformers, switchgear, control and protection equipment will be supplied free issue to the contractor. This phase of the project is for the turnkey contract and equipment supply and installation. The substation is planned to be commissioned at the end of FYE Proposed Purerua Substation Planning studies have shown that it will be necessary to establish a new zone substation in the Purerua region with a new 33kV/11kV, 11.5MVA transformer during the present planning period. The timing of this substation will be dependent on the development of proposed new subdivisions on the Purerua peninsula. The new substation will provide several benefits including, - a) Demand Provision of capacity and maintenance of statutory voltage to the increasing demand in the area, Unloading of Waipapa Substation (11kV feeders), Increased security to the Waipapa substation, Potential for support to the Waipapa substation. The peak demand in the year 2021 is currently forecasted to be 3.8 MVA. b) Capacity The substation will have one 11.5 MVA transformer that is sufficient to supply the forecasted load on the substation for the planning period. c) Security The substation will have one transformer, a single 33kV bus and will be supplied by a single circuit 33kV line via the Waipapa substation. Further study is required to finalise the value of the firm and switched capacity of the substation. Provision will be made to connect the mobile substation. The security level of 2 is assigned to the substation for the planning period under the Top Energy security of supply Standard. 145

148 LIFE CYCLE ASSET MANAGEMENT d) Substation Projects PROJECT NO. DETAILS DRIVER START YEAR BUDGETED COST SUB- DESIGN-PUR-2017 Purerua Substation design EX K$ SUB- LAND-PUR-2018 SUB - New ZS Golf Course location- Purerua-Easements LAND EX SUBS-PROT-PUR-2020 Purerua-Protection RS SUB- CIVIL-PUR-2020 Purerua-Substation Building and Civils - Turnkey EX SUB- SWTCHGR-PUR-2020 Purerua Sub - 11kV Switchboard EX SUB- SWTCHGR-PUR-2020 Purerua Sub- 36kV Tx Panel EX SUB- CABLE-PUR-2020 SUB- CABLE-PUR-2020 SUB- TF-PUR-2021 Purerua-3 x 100m 3c 185mm2 Al XLPE Incomers EX Purerua--Construction of 100 m of 3c 300 mm2 Al XLPE EX SUB - Purerua - New 5/9 MVA transformer EX Figure 106: Proposed Purerua substation projects SUB- DESIGN-PUR-2017: SUB- DESIGN-PUR-2017 The Purerua Peninsular is expected to develop and grow in electricity demand in a similar fashion to the Eastern Bays. Eventually demand will outstrip the 11kV network's capacity to supply the area. Consequently an alternative higher capacity supply line will be required. At present this planned to be either a 22kV supply from Waipapa or a 33kV supply from Waipapa to a new substation on the Peninsular. These alternatives are still being evaluated and the final choice may be determined by line route constraints and the rate of growth experienced. The substation construction will be by means of a turnkey contract. Equipment supply will be free issue from Network to the construction contractor Completion of the substation is planned for This project is for the substation design stage of the work to be undertaken in 2017 SUB- LAND-PUR-2018, SUBS-PROT-PUR-2020, SUB- CIVIL-PUR-2020, SUB- SWTCHGR-PUR-2020, SUB- SWTCHGR-PUR-2020, SUB- CABLE-PUR-2020, SUB- TF-PUR-2021: Purerua Substation Construction The Purerua Peninsular is expected to develop and grow in electricity demand in a similar fashion to the Eastern Bays. Eventually demand will outstrip the 11kV network's capacity to supply the area. Consequently an alternative higher capacity supply line will be required. At present this planned to be either a 22kV supply from Waipapa or a 33kV supply from Waipapa to a new substation on the Peninsular. These alternatives are still being evaluated and the final choice may be determined by line route constraints and the rate of growth experienced. Completion of the line and substation is planned 146

149 LIFE CYCLE ASSET MANAGEMENT for This project is for the purchase of land suitable for the construction of the substation. Land purchase will need to be secured by FYE Distribution Network Reinforcement This section covers projects on the 11kV distribution feeders including single wire earth return (SWER) lines and projects are grouped by zone substation. 11kV distribution feeders have been modelled and investigated for any capacity, security, reliability and voltage compliance issues for the planning period. In addition, the sub-transmission projects described in the above sections will need to be supported by a range of distribution network augmentations. These include projects to divert the distribution network into the new zone substations and create new distribution feeders. In some cases, it may be necessary to increase the conductor size in areas close to new substations, so there is sufficient capacity to accommodate the new injection points, particularly under contingency operating situations. Top Energy has also identified a number of weaknesses in the distribution network and has planned specific projects to address them. Individually, each project is small and has a short lead time. The timing of much of this work is uncertain, as some projects may need to be implemented at relatively short notice to accommodate new loads connecting to specific parts of the network. Therefore, these projects are not specifically identified in this AMP, but are provided for through provisions in the capital expenditure budgets Although a large number of projects are represented below, the dynamic of the distribution system allows for flexibility in the delivery of these projects. Certain operational, staffing and external parameters, such as landowner consents, and weather conditions, may dictate the actual selection choice of projects within the annual budgetary cycle. The overall budgetary value approved by the Board of Directors is a guide and variations to projects or spend is via approved variations Pukenui Substation Te Kao and Pukenui South feeders are supplied by Pukenui substation, one feeding north and the other feeding south of Pukenui respectively. Projects on Feeders There are no distribution projects planned for the Pukenui Substation NPL Substation NPL substation consists of four dedicated industrial feeders and two with mainly domestic load on to them. The investigation showed that all the feeders from the NPL substation meet all the requirements for the planning period Okahu Rd Substation Six feeders are fed from Okahu Rd substation. Four of them are mainly rural feeders and two are urban feeders feeding the Kaitaia town areas. The feeder backbone lengths vary from as short as 3km to as long as 60km. 147

150 LIFE CYCLE ASSET MANAGEMENT PROJECT NO. DETAILS DRIVER START YEAR BUDGETED COST K$ 11kV-OH-OKH kV-INTER-OKH kV-OH-OKH kV-INTER-OKH kV-INTER-OKH kV-OH-OKH-2018 North Rd feeder (KTA town) Conductor upgrade from 16mmCu to Bee (1000m)+ assoc.work (NPL) EX Interconnection between Rangiahua and South Road Feeders (7300m OH) Stage 1 RS Pukepoto and Oxford Street feeders upgrade (300m OH and 300m UG respect.) EX Interconnection between Rangiahua and South Road Feeders (design + first stage) RS Interconnection between Rangiahua and South Road Feeders (7300m OH) Stage 2 RS Conductor upgrade Redan Rd from 25mm Cu to Bee (1050m) EX kV-OH-OKH kV South Rd Feeder conversion EX Figure 107: Okahu Rd substation distribution projects 11kV-OH-OKH-2013: North Rd feeder Conductor upgrade from 16mmCu to Bee (1000m) In order to improve network capability and system reliability during load transfer between feeders, the sections of small conductor (16mm2 Cu) at North Road Feeder is proposed to be replaced with Bee conductor in the FYE kV-INTER-OKH-2015/2016/2018: Interconnection between Rangiahua and South Road Feeders 7300m To provide an alternative supply to both Rangiahua and South Road Feeders for maintenance or fault isolation the 11kV OH interconnection is planned for the FYE 2017, design is for the FYE The connection of this new line into the Rangiahua Feeder will be at S056 (Mangamuka Road) and into the South Road Feeder will be at S026 (Broadwood Road). 11kV-OH-OKH-2016: Pukepoto and Oxford Street feeders upgrade (300m OH and 300m UG respect.) It is identified that the line sections on Pukepoto and Oxford Street Feeders will have voltage drop issues in the year These sections have to be upgraded with the bigger conductor in the year 2016 to mitigate these issues. 11kV-OH-OKH-2018: Conductor upgrade Redan Rd from 25mm Cu to Bee (1050m) It is identified that the line sections on Redan Road Feeder is has voltage drop issues and will be overloaded in the year These sections have to be upgraded with the bigger conductor in the year 2018 to mitigate these issues. 148

151 LIFE CYCLE ASSET MANAGEMENT 22kV-OH-OKH-2022: 22kV South Rd Feeder conversion The South Rd feeder with over 220km of line is one of the longest feeders on Top Energy distribution network. It is recognised that more voltage support needs to be provided on the feeder to mitigate voltage drop issues later in the planning period. The first stage of the major 11kV to 22kV line upgrade on the South Rd feeder is planned in the year Taipa Substation Taipa substation supplies two rural feeders, Oruru and Tokerau, and one low density urban feeder, Mangonui. PROJECT NO. DETAILS DRIVER START YEAR BUDGETED COST K$ SWER-UPGD-PARA-2016 SWER - Line - T /6.3 - Parapara - Convert from kv to 11kV 200kVA - Tokerau Fdr. EX kV-OH-TPA kV Circuits from new substation EX kV-OH-TPA kV-OH-TPA-2021 Oruru feeder conductor upgrade from 16mmCu to Bee (7300m) EX Tokerau Feeder Amps 3 ph Voltage 14km RS Figure 108: Taipa substation distribution projects SWER-UPGD-PARA-2016: SWER Parapara - Convert from kv to 11kV 3 wire - Tokerau Fdr. Investigation has identified voltage drop issues at Parapara. The SWER line conversion to 3 wire is planned in the year 2016 to mitigate these issues. 11kV-OH-TPA-2018: 11kV Circuits from new substation Construction, network integration and commissioning works for the 11kV substation feeders 11kV-OH-TPA-2019: Oruru feeder conductor upgrade from 16mmCu to Bee (7300m) In order to improve network system reliability (load transfer), the section of the Oruru Feeder with 16mm2 Cu conductor has to be upgraded to Bee conductor in FYE kV-OH-TPA-2021: Tokerau Feeder Amps 3 ph Voltage 14km Modelling indicates that the Tokerau feeder requires a distribution voltage regulator to be installed 14km from the substation in the year 2019 to mitigate the voltage drop issues. 149

152 Kaikohe Substation LIFE CYCLE ASSET MANAGEMENT Kaikohe substation feeds seven feeders around Kaikohe town area. These feeders include a feeder to Ngawha Correction Facilities, the Kaikohe town feeder and the Rangiahua feeder which is partially running at 22kV. The voltage compliance related projects are mainly targeted at the Awarua, Horeke, Rangiahua and the Taheke feeders for the planning period due to their lengths. PROJECT NO. DETAILS DRIVER START YEAR BUDGETED COST SWER-UPGD-OMTA-2013 Upgrading SWER to 3 wire at Omahuta EX kV-REC-KHE-2013 Complete job with 192 (controller+lv) RS K$ 11kV-INTER-OKH kV-INTER-KHE kV-INTER-KHE-2019 Interconnection between Rangiahua and Horeke Feeders (design) RS Interconnection between Rangiahua and Horeke Feeders (5420 OH) RS kV OH Interconnection between Rawene and Horeke Feeders (9160m OH) design RS kV-OH-KHE kV-INTER-KHE-2020 Taheke Feeder upgrade design and consenting EX kV OH Interconnection between Rawene and Horeke Feeders (9160m OH) construction RS kV-OH-KHE-2022 Taheke Feeder upgrade EX Figure 109: Kaikohe substation distribution projects SWER-UPGD-OMTA-2013: Upgrading SWER to 3 wire at Omahuta Investigation has identified voltage drop issues on the Rangiahua Feeder, Kaikohe Substation. The Omahuta SWER line conversion to 3 wire is planned in the year 2013 to mitigate these issues. 11kV-REC-KHE-2013: Complete job with 192 (controller+lv) In order to provide the remote operation of switch 192 the controller and LV supply to the controller have to be installed in the year kV-INTER-KHE-2017/18: Interconnection between Rangiahua and Horeke Feeders To provide an alternative supply to both Rangiahua and Horeke Feeders for maintenance or fault isolation the 11kV OH interconnection is planned for the FYE 2018, design is for the FYE New line will be built between L374 and L573. Total length is 5420m. 150

153 LIFE CYCLE ASSET MANAGEMENT 11kV-INTER-KHE-2019/20: Interconnection between Rawene and Horeke Feeders (9160m OH) To provide an alternative supply to both Rawene and Horeke Feeders for maintenance or fault isolation the 11kV OH interconnection is planned for the FYE 2020, Design is for the FYE2019. New line will be built between Curtis Road and Hapanga Road. Total length is 9160m. 11kV-OH-KHE-2019/22: Taheke Feeder upgrade More voltage support needs to be provided on the Taheke feeder to mitigate voltage drop issues later in the planning period. The first stage of the major 11kV to 22kV line upgrade on the Taheke feeder to assist with load transfer between Kaikohe and Omanaia substations is planned in the year Kawakawa Substation Four feeders are supplied from Kawakawa substation. These feeders include two of the most heavily loaded feeders on Top Energy network, Opua and Russell. PROJECT NO. DETAILS DRIVER START YEAR BUDGETED COST 11kV-UG-KWA-2016 UG cable upgrade from KWA (2 feeders) EX K$ 11kV-OH-KAW-2020 Russell Feeder upgrade EX Figure 110: Kawakawa substation distribution projects 11kV-UG-KWA-2016: UG cable upgrade from KWA (2 feeders) It is identified that the UG cables on the entry to the Kawakawa substation will be overloaded in the These UG cables have to be upgraded with the bigger size cables in the year 2016 to mitigate these issues. 11kV-OH-KAW-2020: Russell Feeder upgrade It is recognised that more voltage support needs to be provided on the Russell feeder to mitigate voltage drop issues later in the planning period. The first stage of the major 11kV to 22kV line upgrade on the Russell feeder is planned in the year Moerewa Substation Moerewa substation feeds one industrial and three domestic feeders. AFFCO meat works is supplied by a dedicated feeder that accounts for the major part of the substation load. Moerewa, Tau Block and the Pokapu feeders supply the Moerewa Township and surrounding rural areas. 151

154 LIFE CYCLE ASSET MANAGEMENT PROJECT NO. DETAILS DRIVER START YEAR BUDGETED COST K$ 11kV-OH-MOE kV-OH-MOE kV-INTER-MOE-2017 Conductor upgrade on Moerewa Feeder from 35mm2 to Bee, (660m m) EX Conductor upgrade on Moerewa Feeder (town) from 25mm2 to Bee, (3220m) EX kV OH Interconnection between Puketona and Moerewa Feeders (1320m) RS Figure 111: Moerewa substation distribution projects 11kV-OH-MOE-2013: Conductor upgrade on Moerewa Feeder - 25mm2 & 35mm2 to Bee, (5180m) In order to improve network capability and system reliability during load transfer between Moerewa and Kaikohe substations, the sections of small conductor (25mm2 and 35mm2 Cu) at Moerewa feeder is proposed to be replaced with Bee conductor in the FYE 13 11kV-INTER-MOE-2017: Interconnection between Puketona and Moerewa Feeders (1320m) To provide an alternative supply to both Puketona and Moerewa Feeders for maintenance or fault isolation, the 11kV OH interconnection is planned for the FYE The connection of this new line into the Puketona Feeder will be at Porotu Roadway and into the Moerewa Feeder will be at SH10. This project is for the new 11kV line construction and Entec switch (with LV, communication and controller) as an open point installation Haruru Falls Substation: Haruru Falls Substation supplies four feeders, Tii Bay, Puketona, Onewhero and Joyces Rd. Projects on Feeders PROJECT NO. DETAILS DRIVER START YEAR BUDGETED COST K$ 11kV-INTER-HAR kV-REC-HAR kV-OH-HAR-2021 Load transfer capability HAR-KWA reconductor Joyces Rd & Opua feeders RS Load transfer capability HAR-KWA - switches, etc RS Haruru to Joyces Rd feeder to Williams Rd 5.1 km EX Figure 112: Haruru Falls substation distribution projects 152

155 LIFE CYCLE ASSET MANAGEMENT 11kV-INTER-HAR-2018: Load transfer capability HAR-KWA reconductor Joyces Rd & Opua feeders In order to improve network capability and system reliability during load transfer between feeders, the sections of Joycer Road and Opua Feeders are proposed to be reconductored with Bee conductor in the FYE kV-REC-HAR-2018: Load transfer capability HAR-KWA - switches, etc To improve system reliability (SAIDI), specially during the fault restoration, the manual operated switches proposed to be replace with remote operated switches in the year Use of the remote devices will lead to improved load transferring capabilities as loads can be switched remotely which will lead to a reduction in switching time during planned and unplanned outages (reduced travel time). The project involves: site survey, Entec installation, LV + controller installation. 22kV-OH-HAR-2021: Haruru to Joyces Rd feeder to Williams Rd 5.1 km As part of the Russell cable project the existing Joyces Rd 11kV feeder will need to uprated to 22kV (or 33kV) and new cable laid to the waterfront connection to the submarine cable Waipapa Substation Waipapa substation supplies six feeders all of which are heavily loaded. Some of the load from Totara Nth and Whangaroa feeders and the entire load from the China Clay feeder is planned to be shifted to the proposed Kaeo substation in the year 2018/19. PROJECT NO. DETAILS DRIVER START YEAR BUDGETED COST K$ 11kV-UG-Kauri Cable overlay at Kauri Cliffs EX kV-UG-WPA Figure 113: New Feeder for Waipapa Business Centre-11kV 300 mm2 Al Cable Waipapa substation distribution projects EX kV-UG-Kauri-2013: Cable overlay at Kauri Cliffs A series of similar cable faults on the Kauri Cliffs underground cable network strongly suggests faulty cable which needs to be replaced. This is the last stage of this cable replacement programme 11kV-UG-WPA-2014: New Feeder for Waipapa Business Centre-11kV 300 mm2 Al Cable In order to prevent industrials customers suffer from autoreclosing due to the faults down the line, new feeder was proposed to carry out Waipapa Industrial load, thereby, the security of industrial supply will increase as well as voltage quality at the existing feeder (after taking load off) 153

156 Omanaia Substation LIFE CYCLE ASSET MANAGEMENT Omanaia substation is the smallest substation on Top Energy s network. It feeds into the area south of the Hokianga harbour via two feeders: Opononi and Rawene. Projects on Feeders PROJECT NO. DETAILS DRIVER START YEAR BUDGETED COST K$ SWER-UPGD-WMA-2013 Upgrading SWER to 3 wire at Waima Valley Road EX kV-REC-OMA-2013 Replacing switches 655, 554 with ENTEC RS kV-AUTO-OMA-2013 Self-Healing Network at Omanaia RS kV-AUTO-OMA kV Feeder automation RS kV-OH-OMA kV-OH-OMA-2013 Upgrading Bare Cu 25mm2 to Bee conductor Omanaia (design) EX Upgrading Bare Cu 25mm2 to Bee conductor Omanaia (construction) EX PROT-FDR-OMA-2018 T1 Transformer Protection Upgrade RS kV-REC-OMA-2018 SUB- TF-OMA KV-OH-OMA-2020 Remotely operated Entec switch for new interconnection (Rawene and Horeke) RS SUB - OMA - install 6.25MVA ex Taipa with CB EX kV - OMA - New 33kV line to Omanaia substation. Design and Property RS Figure 114: Omanaia substation distribution projects SWER-UPGD-WMA-2013: Upgrading SWER to 3 wire at Waima Valley Road Investigation has identified voltage drop issues on the Rawene Feeder, Omanaia Substation. The SWER line conversion to 3 wire is planned in the year 2013 to mitigate these issues. 11kV-REC-OMA-2013: Replacing switches 655, 554 with ENTEC To improve system reliability (SAIDI), specially during the fault restoration, the manual operated switches proposed to be replace with remote operated switches in the year Use of the remote devices will lead to improved load transferring capabilities as loads can be switched remotely which will lead to a reduction in switching time during planned and unplanned outages (reduced travel time). The project involves: site survey, Entec installation, LV+controller installation. 154

157 LIFE CYCLE ASSET MANAGEMENT 11kV-AUTO-OMA-2013: Self-Healing Network at Omanaia - 11kV Feeder automation To track conditions on OH systems and quick automatic service restoration in response to an outage or fault, the self-healing network realized on Top Energy standard RTUs was proposed as a trial project at Omanaia Substation Feeders in the year Project involves RTUs programming and extra RTUcontroller installation as a PLC device. In order to build the self-healing network, the remotely operated switches have to replace existing manually operated switches at Rawene and Opononi Feeders, Omanaia Substation. Project involves: replacement of switches 724, 320, 423 with Entec (including LV and controller). 11kV-OH-OMA-2013: Upgrading Bare Cu 25mm2 to Bee conductor Omanaia Investigation has identified voltage drop issues due to a small size of the conductor at Opononi Feeder from S1029 to switch 157. The conductor planned to be replaced with Bee conductor in the year 2014 to mitigate these issues. The design is planned for the year The line of replacement is approx. 5900m length. 11kV-REC-OMA-2018: Horeke) Remotely operated Entec switch for new interconnection (Rawene and In order to transfer load remotely between connected feeders, the remotely operated device have to be installed prior to interconnection construction in FYE Job includes Entec switch installation (survey, LV, controller and comms) Kerikeri Substation PROJECT NO. DETAILS DRIVER START YEAR BUDGETED COST 11kV-UG-KER kV Feeder Interconnections EX kV-UG-KER kV Feeder Interconnections EX K$ 11kV-INTER-KER kV-REC-KER kV-INTER-KER Interconnection between "Inlet Road" and Onewhero (design) Remotely operated Entec switch for new interconnection (Inlet Road and Onewhero) Interconnection between "Inlet Road" and Onewhero feeders (6500m) RS RS RS kV-UG-KER-2020 Underground Design RS kV-UG-KER-2021 Kerikeri Rd 11kV underground RS kV-UG-KER-2022 Underground 11kV Honeheki Rd RS Figure 115: Kerikeri substation distribution projects 155

158 LIFE CYCLE ASSET MANAGEMENT 11kV-UG-KER: 11kV Feeder Interconnections In order to connect Kerikeri Substation into the surrounding 11kV network and configure the network so that feeder loads are balanced, and interconnections are optimally placed operationally, significant 11kV reticulation augmentation is required, both underground and overhead. 11kV-INTER-KER: Interconnection between "Inlet Road" and Onewhero To provide an alternative supply to both Inlet Road and Onewhero Feeders for maintenance or fault isolation the 11kV OH interconnection is planned for the FYE 2019, design is for the FYE New line will be built between Kerikeri Inlet Road (L501) and Te puke Road. Total length is 6500m. 11kV-REC-KER-2018: Remotely operated switch for new interconnection (Inlet Road and Onewhero) In order to transfer load remotely between connected feeders, the remotely operated device have to be installed prior to interconnection construction in FYE Job includes Entec switch installation (survey, LV, controller and comms) 11kV-UG-KER: Kerikeri Rd 11kV underground For aesthetic and security reasons it is planned to install underground cable in place of the existing OH line along Kerikeri and Honeheke Rds. The OH line to UG cable replacement is planned for the year 2021 and 2022 with the design work being undertaken in Kaeo Substation PROJECT NO. DETAILS DRIVER START YEAR BUDGETED COST 11kV-REC-KAO Open point between Rangiahua, Xroads and Totara North Feeders (replace 289 with Entec) K$ RS kV-UG-KAO Kaeo - 5 x new feeder out of substation EX Figure 116: Kaeo substation distribution projects 11kV-REC-KAO-2014: Open point between Rangiahua, Xroads and Totara North Feeders In order to improve network system reliability (load transfer), the open points between Kaikohe, Mt Pokaka and Waipapa substation were proposed on Entec switches to allow remote load transfer between 11 kv feeders in FYE Replace the existing switch with an Entec 11kV-UG-KAO-2018: Kaeo - 5 x new feeders out of substation Construction, network integration and commissioning works for the 11kV substation feeders 156

159 LIFE CYCLE ASSET MANAGEMENT Whatiwhiwhi Substation PROJECT NO. DETAILS DRIVER START YEAR BUDGETED COST K$ 11kV-OH-WHI Figure 117: 11 kv connections to Whatuwhiwhi Sub EX Whatiwhi substation distribution projects Reinforcement of the Supply to Russell The Russell peninsula is relatively inaccessible, with main vehicle access required by car ferry from Opua. However, it is an area that has seen a high level of subdivision in recent years and where there is a relatively high load growth. The area is supplied through two 11kV submarine cables, one across the Waikare inlet east of Opua and the second between Opua and Okiato Point, along the route of the car ferry. Both cables are supplied from the Kawakawa zone substation. Top Energy has a resource consent that expires in 2014 to install a third submarine cable that will run directly from the beach front at Paihia to the south end of Russell village, Top Energy is planning to seek an extension to this consent. Under normal operation, the Russell load is carried on the older cable across the Waikare inlet. The newer cable from Opua is connected to the relatively heavily loaded Opua feeder and is used as a backup. As a short-term measure to reinforce the supply to Russell, it is planned to move all existing load on the south side of the Waikare inlet from the Russell to the Kawakawa feeder and to create an express feeder with no connected load between the zone substation and the submarine cable. Upgrading this express section of the feeder to 22kV has also been considered. However, while these options would increase the capacity into the peninsula under normal operation, there would still be a constraint in the event of a fault on the submarine cable. If an extension to the resource consent is granted, Top Energy can install the third submarine cable around FYE This would provide a high capacity supply into Russell, which would be supplied from the Haruru zone substation through a dedicated feeder. The new cable will be rated at 33 kv, although it will initially be operated at 11kV or possibly 22kV. An alternative option, which would delay the requirement for the third submarine cable, would be to establish a small power station in Russell using the generators currently located at Taipa. Construction of a new zone substation in Russell is not contemplated within the planning period. Moving the Russell feeders from the Kawakawa to Haruru zone substations will utilise available spare capacity at Haruru and defer any need to increase the transformer capacity at Kawakawa. 157

160 LIFE CYCLE ASSET MANAGEMENT Network Communications/SCADA/Security Projects PROJECT NO. DETAILS DRIVER FYE START BUDGETED COST K$ COMMS-1OFFICE-VAR-2013 One office SCADA WAN KTA, KOE RS SCADA-RTU-VARIOUS-2013 Conversion of Regulator RTUs RS COMMS-FIBRE-KAW COMMS-FIBRE-MTP-2013 COMMS-FIBRE-PUK-2013 COMMS-WAN-Var-2013 Fibre install - kawakawa No2 Stage 7 km RS Fibre install - Mt Pokaka interconnection RS Fibre install - Church Rd to KTA - 3.5km RS WAN router installation for 13 Substations RS COMMS-STP Cbl-Var-2013 STP cabling for 12 substations RS COMMS-MOE-Moxa-2013 COMMS-HAR-Moxa-2013 COMMS-VHF-VoIP-2013 Moerewa Moxa Switch and media converter RS Haruru Moxa Switch and media converter RS VHF Voice repeater linking and VoIP connectivity RS COMMS-VHP-RoIP-2013 Soft Radio RoIP RS SCADA-CABINET-VAR-2013 COMMS-FIBRE-KAW COMMS-FIBRE-OKH-2014 SCADA-RTU-VARIOUS-2014 COMMS-FIBRE-HAR-2014 SCADA-CABINET-VAR-2014 Scada Cabinet replacements - 4 off RS Fibre install - kawakawa No2 Stage 9.5km RS Fibre install - KTA to NPL via OKH 13.5 km RS Conversion of Recloser RTUs - Upgrade of TOPCAT 1s RS Fibre install Southern area HAR - MOE 22km Stage 1 RS Scada Cabinet replacements - 4 off RS

161 LIFE CYCLE ASSET MANAGEMENT PROJECT NO. DETAILS DRIVER FYE START BUDGETED COST K$ FIBRE-MOE/KWA-2015 COMMS-SCADA/REG-2015 SUBS-SECURITY SUBS-SECURITY COMMS-FIBRE-KTA-2017 COMMS-FIBRE-VARIOUS-2021 Fibre install Southern area MOE - KWA 7.5km Stage 2 RS Regulator SCADA Communications RS Security systems for substations - stage 1 RS Security systems for substations - stage 2 RS Fibre install - North 10km South 15km RS Fibre install - 50km on existing lines RS Figure 118: 1Communication/SCADA/Security projects Transmission Projects PROJECT NO. DETAILS DRIVER FYE START BUDGETED COST K$ TRANS-PURCHASE-2013 Purchase of Transpower Assets Transmission TRANS-STRUCT-VAR-2013 KOE - KTA Structure Replacements Transmission TRANS-CB-KOE-2014 Kaikohe GXP CB Replacements Transmission TRANS-CB-KOE-2014 KTA GXP CB replacement Transmission TRANS-CB-KOE-2014 KTA GXP CB replacement Transmission TRANS-CB-KOE-2014 Kaikohe GXP CB Replacements Transmission TRANS-CB-KOE-2014 KTA GXP CB replacement Transmission TRANS-CB-KOE-2014 KTA GXP CB replacement Transmission TRANS-CB-KOE-2015 Kaikohe GXP CB Replacements Transmission

162 LIFE CYCLE ASSET MANAGEMENT PROJECT NO. DETAILS DRIVER FYE START BUDGETED COST K$ TRANS-CB-KOE-2015 Kaikohe GXP CB Replacements Transmission TRANS-CB-KOE-2015 Kaikohe GXP CB Replacements Transmission TRANS-DS-KOE-2015 Kaikohe GXP DS Replacements Transmission TRANS-DS-KTA-2015 KTA GXP DS replacement Transmission TRANS-DS-KOE-2015 Kaikohe GXP DS Replacements Transmission TRANS-DS-KTA-2015 KTA GXP DS replacement Transmission TRANS-DS-KTA-2015 KTA GXP DS replacement Transmission TRANS-DS-KOE-2015 Kaikohe GXP DS Replacements Transmission TRANS-DS-KTA-2015 KTA GXP DS replacement Transmission TRANS-PROT-KOE-2016 Kaikohe GXP Protection Replacements Transmission TRANS-PROT-KTA-2016 KTA GXP Protection replacement Transmission TRANS-PROT-KTA-2016 KTA GXP Protection replacement Transmission TRANS-PROT-KTA-2016 KTA GXP Protection replacement Transmission TRANS-PROT-KOE-2016 Kaikohe GXP Protection Replacements Transmission TRANS-PROT-KTA-2016 KTA GXP Protection replacement Transmission TRANS-PROT-KOE-2017 Kaikohe GXP Protection Replacements Transmission TRANS-PROT-KTA-2017 KTA GXP Protection replacement Transmission TRANS-SWTCH-KTA-2017 TRANS-LINE-DESIGN-2017 TRANS-LINE-STAGE KTA GXP 33kV Switchgear replacement - Design Transmission Kaikohe Kaitaia 110kV line rebuild - Design and Consenting Transmission Kaikohe Kaitaia 110kV line rebuild - stage 1 Transmission

163 LIFE CYCLE ASSET MANAGEMENT PROJECT NO. DETAILS DRIVER FYE START BUDGETED COST K$ TRANS-SWTCH-KTA-2018 TRANS-LINE-STAGE TRANS-SWTCH-KTA-2019 KTA GXP 33kV Switchgear replacement Transmission Kaikohe Kaitaia 110kV line rebuild - stage 2 Transmission KTA GXP 33kV Switchgear replacement Transmission TRANS-BATT-KOE-2019 Kaikohe GXP Batteries Replacements Transmission TRANS-BATT-KTA-2019 KTA GXP Batteries replacement Transmission TRANS-ES-KOE-2019 Kaikohe GXP ES Replacements Transmission TRANS-BLDG-KOE-2019 Kaikohe GXP Buildings and Grounds Transmission TRANS-BATT-KOE-2019 Kaikohe GXP Batteries Replacements Transmission TRANS-BLDG-2019 Buildings and Grounds Transmission TRANS-BATT-KTA-2019 KTA GXP Batteries replacement Transmission TRANS-TWR-PAINT-2019 KOE - KTA Tower Paint Transmission TRANS-ES-KOE-2019 Kaikohe GXP ES Replacements Transmission TRANS-BLDG-KTA-2019 Buildings and Grounds Transmission TRANS-ES-KOE-2019 Kaikohe GXP ES Replacements Transmission TRANS-ES-KTA-2019 KTA GXP ES replacement Transmission TRANS-LINE-STAGE TRANS-LINE-STAGE Kaikohe Kaitaia 110kV line rebuild - stage 3 Transmission Kaikohe Kaitaia 110kV line rebuild - stage 4 Transmission TRANS-VARIOUS-2022 Equipment replacements Transmission Figure 119: Transmission projects 161

164 LIFE CYCLE ASSET MANAGEMENT Asset Replacement Projects PROJECT NO. DETAILS DRIVER FYE START BUDGETED COST K$ ARP-HV-FLD-SW-STG ARP-ST-FLD-PO-STG ARP-HV-FLD-TX-STG00-WAI ARP-DC-STN-AU-STG00-KAW/HAR Waitangi Kiosk Switchgear Replacement RR Pukenui 33kV Feeder Rebuild [Wood Poles Stage 2] RR Distribution Surge Arrestor Program - Waipapa RS Zone Substation Battery Replacement - Kawakawa/Haruru RR RFQ KHO OMAHUTA SWER Omahuta SWER Rebuild RR ARP-HV-FLD-PO-STG Reconductor - Mungakahia Rd RR ARP-HV-FLD-PO-STG Reconductor - Quarry Rd RR ARP-RT-FLD-AU-STG00-RATEA ARP-ST-FLD-PO-STG ARP-HV-FLD-PO-STG00-OKA ARP-ST-FLD-PO-STG ARP-ST-FLD-PO-STG Replace Ratea Radio Repeater Site RR Pukenui 33kV Feeder Rebuild [Wood Poles Stage 3] RR Distribution Surge Arrestor Program - Okahu RS Kawakawa 1 33kV Feeder Rebuild [Wood Poles] RR Waipapa 2 33kV Feeder Rebuild [Wood Poles] RR ARP-HV-FLD-PO-STG Refurbishment - Hapunga Rd RR ARP-HV-FLD-SW-STG01-MULTIPLE ABS Replacement RR ARP-HV-FLD-TX-STG00-KAW ARP-ST-FLD-PO-STG ARP-ST-FLD-PO-STG Distribution Surge Arrestor Program - Kawakawa RS Taipa 33kV Feeder Rebuild [Wood Poles] RR Kawakawa 1/Waipapa 2 33kV DC Feeder Rebuild [Wood Poles] RR ARP-HV-FLD-TX-STG01-MULTIPLE OH PM Transformer RR

165 LIFE CYCLE ASSET MANAGEMENT PROJECT NO. DETAILS DRIVER FYE START BUDGETED COST K$ Replacements ARP-ST-FLD-PO-STG Pukenui 33kV Feeder Rebuild [Wood Poles Stage 4] RR ARP-HV-FLD-SW-STG02-MULTIPLE ABS Replacement RR ARP-ST-FLD-PO-STG Pukenui 33kV Feeder Rebuild [Wood Poles Stage 5] RR ARP-HV-FLD-PO-STG01-MULTIPLE Pole Replacements RR ARP-DC-STN-AU-STG00-OMA Zone Substation Battery Replacement - Omanaia RR ARP-LV-FLD-PI-STG01-MULTIPLE Pillar Replacement RR ARP-HV-FLD-SW-STG03-MULTIPLE ABS Replacement RR ARP-HV-FLD-PO-STG02-MULTIPLE Pole Replacements RR ARP-HV-FLD-PO-STG03-MULTIPLE Pole Replacements RR ARP-HV-FLD-SW-STG04-MULTIPLE ABS Replacement RR ARP-HV-FLD-TX-STG02-MULTIPLE OH PM Transformer Replacements RR ARP-HV-FLD-PO-STG04-MULTIPLE Pole Replacements RR ARP-HV-FLD-TX-STG03-MULTIPLE OH PM Transformer Replacements RR ARP-HV-FLD-SW-STG05-MULTIPLE ABS Replacement RR ARP-EA-FLD-TX-STG01-MULTIPLE ARP-ST-FLD-PO-STG PM Transformer Earth Remediation RS Okahu/NPL 33kV DC Feeder Rebuild [Wood Poles] RR ARP-HV-FLD-PO-STG05-MULTIPLE Pole Replacements RR ARP-LV-FLD-PI-STG02-MULTIPLE Pillar Replacement RR ARP-EA-FLD-TX-STG02-MULTIPLE PM Transformer Earth Remediation RS

166 LIFE CYCLE ASSET MANAGEMENT PROJECT NO. DETAILS DRIVER FYE START BUDGETED COST K$ ARP-HV-FLD-SW-STG06-MULTIPLE ABS Replacement RR ARP-HV-FLD-PO-STG06-MULTIPLE Pole Replacements RR ARP-LV-FLD-PI-STG03-MULTIPLE Pillar Replacement RR ARP-ST-FLD-PO-STG Omania 33kV Feeder Rebuild [Wood Poles] RR ARP-HV-FLD-PO-STG07-MULTIPLE Pole Replacements RR ARP-EA-FLD-TX-STG03-MULTIPLE PM Transformer Earth Remediation RS ARP-LV-FLD-PI-STG04-MULTIPLE Pillar Replacement RR ARP-HV-FLD-PO-STG08-MULTIPLE Pole Replacements RR ARP-HV-FLD-RG-STG00-MULTIPLE Regulator Replacements RS Figure 120: Transmission projects 164

167 5.9.8 Future Network LIFE CYCLE ASSET MANAGEMENT Figure 121 is a schematic diagram of what Top Energy envisages the network will look like at the end of the planning period. Figure 121: Proposed Infrastructure FYE

168 5.9.9 Communications System LIFE CYCLE ASSET MANAGEMENT Top Energy s communications network is based on a range of low bandwidth voice technologies it have reached the end of their operational life. It does not have the speed or data capacity requirements to take advantage of the functionality that is now provided in modern digital protection and control equipment and provide features that are now considered industry standard. For example, signalling delays make the existing communication network unsuitable for protection signalling. During the latter half of FYE 2011, TEN engaged Tesla Consultants Ltd to undertake a strategic review of the existing distribution and sub-transmission network communications technology, in relation to the future operational requirements of the TEN Network Development Plan (TE2020). This section details the outcome of that report, together with strategy to meet the rapid expansion of the system over the next 10 years. The assessment was limited to operational and voice telecommunications systems, which are defined as: substation automation, SCADA, protection signalling and business access to these systems, and voice telecommunications to mobile and fixed transceivers on remote equipment. The strategic solution includes: future proofing of capacity to cover information services or business system requirements, such as voice, video surveillance, access security, , file and print or business applications to the substations. This detailed Tesla report included the strategic business requirements and principles, network topology, substation automation technologies, disaster recovery, spares and a recommended strategic plan for the project. It also provided an outline for the future of the Top Energy operational and voice communication networks that have subsequently been included in the strategy. The technology options reviewed include: copper cables, fibre optic cables, digital microwave radio, wideband UHF radio, point-to-multipoint radio, satellite services, leased wireless services and leased data services. Infrastructure requirements for radio repeater sites, voice communications, IP and wireless SCADA networks and substation LAN equipment were also reviewed. A key driver for the network strategy is to ensure that the proposed solution kept pace with the growth of the network and is a key enabler in delivering value, in terms of security of supply, by actively contributing to the reduction in network SAIDI and SAIFI results. Likewise, there is a focus on improving communications reliability, incorporation of SCADA, voice, IP, serial and protection services, and achieving a maximum downtime per year of 4 hours (99.95%), 8 hours available operational time in the event of a blackout, multiple routes (to provide diverse redundancy to the core disaster recovery site), and a reduction in the dependency on existing outdated and high maintenance equipment. Top Energy will install fibre optic cables with all new sub-transmission lines and add fibre optic cables to selected existing lines. A core, robust network connection will be established linking the southern and northern areas by utilising this new fibre cable and adding a new wideband UHF radio link to close a north-south ring. This will also provide an operational level of redundancy, in case of failure of the primary fibre link. Where new lines are not planned and distances make installation of new fibre on existing lines uneconomic, wideband UHF links will be used to connect to substations. All new installations will include multiplexers to allow for protection signalling services concurrently with IP network operational and business services. For voice radio-telephone, the existing radio equipment will be retained to end-of-life, but integrated into the new communications network with Voiceover IP interfaces. Pole top, low-speed data will remain on the existing VHF infrastructure to service operational equipment, such as reclosers and sectionalisers, but will use similar IP interfaces to allow SCADA to operate through the new IP network. 166

169 LIFE CYCLE ASSET MANAGEMENT Figure 122: Top Energy Communications Overlay FYE2020 As detailed above, the new communications network development will be linked to the TE2020 construction programme with the main fibre systems installed within existing substations over the ten year transmission and subtransmisson build programme. Outlying substations, such as Whatuwhiwhi and Purerua, will be serviced as they are constructed in line with future load growth, so they may fall outside of the planning period. Strategic Business Objectives The main objective for Top Energy in developing a communications network is to ensure that it not only keeps pace with the growth and upgrade of the distribution network, but is a key enabler in delivering the value of the distribution network projects in terms of network performance, reliability and security of electricity supply. The telecommunications network plays a vital role in the security of the electricity supply with the interconnection of data across the distribution network in real-time and the delivery of information that immediately impacts on the performance of the distribution network. The reduction of the annual SAIDI and SAIFI minutes is vital to this role. SAIDI minutes are impacted significantly by the telecommunications network, the mobile voice networks and SCADA systems play a major role in staff response time to distribution network faults. Therefore, a key performance driver for the Top Energy telecommunication network is the availability and reliability of the mobile voice network and the SCADA network. SAIFI, however, is significantly affected by equipment failure and, accordingly, is a measure of asset quality and maintenance practices. SAIFI is seriously impacted by a response within the first minute, which is the time period before SAIDI and SAFI are reportable. This encourages the automation of feeders and their associated equipment to keep outage durations to less than a minute. Therefore, a key performance driver for the Top Energy telecommunications network is the ability to seamlessly 167

170 LIFE CYCLE ASSET MANAGEMENT and, in a timely manner, allow the different distribution network layers (pole tops, substations and control room equipment) to communicate with each other. To deliver on the primary strategies above, the key is delivery of information in a timely manner to the operators or the systems that are responsible for making decisions for control of the distribution network. This entails the connection of protection relays, RTU s, reclosers and switches from substations and pole top structures to the central SCADA system and, where appropriate, to each other for smart automated switching schemes. The telecommunications network is a key enabler for delivering on these primary strategies as is the substation/pole top equipment and the SCADA system. It allows the overall end to end delivery of critical information for the control and monitoring of the distribution network. Another important strategic objective is to maximise the value of the telecommunications network deployed and to future proof Top Energy in regard to changing technologies. This would be achieved by bringing together all of the telecommunications network services across Top Energy to take full advantage of changing technologies. Alternatively, possible business opportunities may arise for shared use of telecommunications infrastructure with separate parties. The installation of new telecommunication links, especially based on fibre optic cables may provide an opportunity for cost and revenue sharing with other parties, however such opportunities will require thorough analysis to assess inherent risk and operational obligations. Architecture Summary With reference to the above strategic business objectives, technology options, network topology, substation automation technologies, disaster recovery and the TE2020 network development plan, the following communications strategic plan has been developed. 1. Fibre Optic cable will be used whenever this can be incorporated within the construction of a new line. 2. Fibre optic cable will be used where the route distance is small and running costs economic. 3. Wideband UHF radio will be used for substation links where fibre cables are not economic. 4. Multiplexers will be used when protection signalling services are implemented. 5. Ring topology for the core network, star connections to substations with provision for substation rings where justified. 6. Options for use of leased dark fibres (as an alternative to building fibre links) will be investigated on a case by case basis. Adoption of the architecture strategy listed above will deliver a communications network plan in five main sections, a Core Network, a Northern Network, a Southern Network, a voice network and a poletop network. An additional advantage is the possibility for development of a business communications network for limited additional cost. Core Communications Network The core communications network will interconnect the following sites: Kaikohe TECC Kaikohe GXP Wiroa Kaeo Kaitaia GXP These sites were chosen as they lie on, or very close to (in the case of Kaeo), the proposed new 110kV line from Kaikohe GXP to Kaitaia GXP. 168

171 LIFE CYCLE ASSET MANAGEMENT The ring will be completed with a Digital Microwave Radio (DMR). This link will pass through the following sites: Kaikohe TECC Mt Hikurangi Repeater Maungataniwha Repeater Kaitaia GXP Figure 123: Core Communications Network Architecture The key projects for the core network are: 1. Installation of a fibre optic cable with the new 110kV line construction, 2. Installation of a fibre optic cable from Kaikohe TECC to Kaikohe GXP, 3. Utilisation of the fibre optic cable for linking Kaikohe GXP Wiroa Kaeo Kaitaia GXP, 4. Installation of a new digital microwave radio link from Kaikohe TECC to Kaitaia GXP via Mt Hikurangi and Maungataniwha, 5. Installation of multiplexers at Kaikohe GXP, Wiroa, Kaeo and Kaitaia GXP, 6. Installation of IP routing at the Kaikohe GXP, Wiroa and Kaitaia GXP, and 7. Installation of a standard substation IP infrastructure at all sites within the core ring. Southern Area Communications Network The southern area communications network will interconnect the following sites: Ngawha Pakaraka Moerewa Kawakawa Haruru Mt Pokaka Kerikeri 169

172 LIFE CYCLE ASSET MANAGEMENT Waipapa Purerua All new links included in this section of the communications network will be fibre optic cables. The existing Eclipse DMR from Kawakawa to Moerewa has been included. One fibre cable is shown to Ngawha, however, as this is the DR site, communication diversity will be implemented. One cable is currently under construction, on the new Ngawha Kaikohe GXP line and a second fibre cable will be installed along the existing Ngawha Worsnop Kaikohe GXP line, to provide a diverse ring. Figure 124: Southern Area Communications Network Architecture The key projects for the southern network are: 1. Installation of infrastructure at Pakaraka for communications equipment, 2. Installation of a fibre optic cable Kaikohe GXP Pakaraka, 3. Installation of a fibre optic cable Pakaraka Moerewa, 4. Installation of a fibre optic cable Pakaraka Haruru, 5. Extend the existing fibre optic cable from Mt Pokaka Wiroa, 6. Installation of a fibre optic cable Wiroa Kerikeri, 7. Installation of a fibre optic cable Kerikeri Waipapa, 8. Installation of a fibre optic cable Waipapa Purerua, 9. Upgrade of repeater infrastructure at Duddy Rd to support wideband UHF equipment, 10. Installation of wideband UHF radio link Mt Hikurangi Repeater Duddy Rd, 11. Installation of a fibre optic cable Duddy Rd Omanaia, 12. Installation of multiplexers at Ngawha, Pakaraka, Moerewa, Kawakawa, Haruru, Mt Pokaka, Kerikeri, Waipapa and Purerua as protection signalling services are deployed, and 13. Installation of a standard substation IP infrastructure at all sites in this area. 170

173 LIFE CYCLE ASSET MANAGEMENT Northern Area Communications Network The northern area communications network will interconnect the following sites: Okahu NPL Awanui Pukenui Taipa The network in the northern area will consist mostly of radio, with two fibre cable links. A new fibre cable will be installed between Kaitaia GXP and NPL, and then radios will be used to communicate to the adjacent substations. NPL was selected for a fibre install to provide acceptable service to the adjacent depot, plus to provide an adequate link to aggregate the data requirements of the three substations linked through NPL. Wideband UHF radios have been selected for Okahu and Awanui, as these radios can include integrated multiplex at very low cost and the links are very short (frequency bands allowed to be used for links this short are restricted by the licensing authority). Similar UHF radios are planned for links to Taipa and Pukenui. A ring is possible by installing a radio link from Maungataniwha to Taipa. Figure 125: Northern Area Communications Network Architecture The key projects for the northern network are: 1. Installation of infrastructure at Pakaraka for communications equipment, 2. Installation of a fibre optic cable Kaitaia GXP NPL, 3. Installation of UHF wideband radio Okahu NPL, 4. Installation of UHF wideband radio NPL Awanui, 5. Installation of UHF wideband radio Maungataniwha Repeater Pukenui, 6. Installation of a fibre optic cable Awanui Taipa, 7. Installation of multiplexers at Okahu, NPL, Awanui, Pukenui, and Taipa as protection signalling services are deployed, and 8. Installation of standard substation IP infrastructure at all sites in this area. 171

174 LIFE CYCLE ASSET MANAGEMENT Voice Network (VHF Radio) The existing voice VHF repeaters are reported to be performing well, but some are difficult to access from TECC. Should a change away from the existing basic analogue radio technology be implemented, this would need to be completed as a single project, replacing all repeaters and vehicle radios simultaneously, this would be disruptive and has major logistical issues. Current digital mobile radio technologies offer little improvement for single-channel owner-operator users. In addition to this, digital mobile radio repeaters typically have much higher standby operating current than basic analogue equipment, which could be a problem at Top Energy solar powered sites. It is likely that basic analogue radios will continue to be available for at least 10 years and probably well beyond this, with modern units actually constructed around a digital processor and using current technology internally already. Top Energy will therefore retain existing equipment and make improvements with a new VoIP based linking system over the new communications network, with centralised console and the ability to access remotely from other locations on the network. As repeaters are replaced over time, it is likely the replacement equipment will have direct IP interface that will connect directly to the network and remain compatible with the centralised console. The new VoIP linked network will look like this: Figure 126: Voice Network Architecture The key projects for the voice network are as follows: 1. Installation of a VoIP interface to voice repeaters at Maungataniwha and Ngawha, 2. Installation of a VoIP interface to trigger radios at Okahu, Wiroa and TECC, 3. Installation of an Omnitronics console with two bus linking facility at TECC, and 4. Installation of Omnitronics SIP consoles at locations where there is a direct requirement for access to voice repeaters. Sites to be determined as part of the future planning process.. Voice Network Interim Solution Top Energy will use a redundant UHF J band point-to-point repeater to provide improved voice linking between TECC and repeaters in the northern area as an interim measure until the VoIP linking solution can be implemented. 172

175 LIFE CYCLE ASSET MANAGEMENT Figure 127: Voice Network Interim Architecture The voice network interim solution is as follows: 1. Redeployment of redundant J11 radios to provide access from TECC to Maungataniwha. Okahu and Pukenui, and 2. Dismantle this arrangement as the new VoIP solution is rolled out. Pole Top Data The existing data VHF repeaters are reported to be performing well for pole top SCADA. The pole top data repeater network will be integrated into the new IP network in a similar manner to the voice network, IP/serial modem devices will be connected directly to the repeater, where the IP network passes or to trigger radios installed at nearby substations on the IP communications network. Figure 128: Pole Top Data Network Architecture We will implement the following for the VHF data network: 1. IP/serial modem interface to data repeaters at Maungataniwha, Wiroa, Okahu and Ngawha, and 2. IP/serial modem interface to trigger radios at Okahu and TECC. 173

176 $x Breakdown of the Capital Expenditure Budget LIFE CYCLE ASSET MANAGEMENT The ten year capital expenditure budget is detailed below. The transmission expenditure for FYE 2013 includes the cost of transferring the transmission assets from Transpower. A more detailed breakdown of the asset replacement and renewal capital expenditure budget, which is maintenance driven, is provided in Section ,000 30,000 25,000 20,000 15,000 10,000 5,000 0 Capital Expenditure Forecast Transmission Reliability, Safety and Environment System Growth Customer Connections Asset Replacement Figure 129 Capital Expenditure Category Spend Profile FYE 2013 to FYE 2022 The Figure below detail the breakdown of forecast capital expenditure viewed from a regulatory cost category comparison. FYE Customer Connection System Growth Asset Replacement and Renewal Reliability, Safety and Environment Asset Relocations Transmission Total - Capital Expenditure ,045,000 11,821,590 3,000,000 6,596,500-6,706,000 29,169, ,045,000 6,567,000 3,000,000 11,085,000-3,047,076 24,744, ,045,000 3,580,000 3,100,000 9,889,500-4,124,854 21,739, ,045,000 6,934,000 3,400,000 6,393, ,337 18,447, ,045,000 6,585,000 3,500,000 7,857, ,181 19,969, ,050,000 5,256,000 3,800,000 5,374,000-3,510,000 18,990, t 1,045,000 7,262,500 3,800, ,000-3,260,878 15,958, ,045,000 7,387,000 4,400,000 1,080,000-2,080,000 15,992, ,045,000 3,212,000 4,500,000 3,929,764-3,250,000 15,936, ,050,000 3,295,000 5,570,000 5,500, ,000 15,915,000 Figure 130 Forecast Capital Expenditure FYE 2013 FYE

177 LIFE CYCLE ASSET MANAGEMENT Section 6 Life Cycle Asset Management 6 L i f e c y c le A s s e t M a n a g e m e n t Maintenance and Renewal Planning Criteria and Assumptions Maintenance and Renewal Criteria Routine and Preventative Maintenance Programme Renewal Maintenance Programme Reactive Maintenance Asset Replacement Transmission Assets Overhead Conductors Failure Modes and Risks Associated with Overhead Conductors Planned Inspection & Maintenance Practices for Overhead Conductors Vegetation Strategy Regulatory Compliance Far North District Council (FNDC) Relationship Targeted Cutting Strategy Poles and Structures Failure Modes and Risks Associated with poles and structures Planned Inspection & Maintenance Practices for Poles and Structures Asset Renewal Programme Underground & Submarine Cables Failure Modes and Risks Associated with Underground & Submarine Cables Planned Inspection & Maintenance Practices for Underground & Submarine Cables Asset Renewal Program Distribution and SWER Transformers Failure Modes and Risks Associated with Distribution and SWER Transformers Planned Inspection and Maintenance Practices for Distribution and SWER Transformers Asset Renewal Program Auto-Reclosers Failure Modes and Risks Associated with Auto-Reclosers Planned Inspection and Maintenance Practices for Auto-Reclosers Asset Renewal Program Regulators Failure Modes and Risks Associated with Regulators Planned Inspection and Maintenance Practices for Regulators Asset Renewal Program Ring Main Units (RMU)

178 LIFE CYCLE ASSET MANAGEMENT Failure Modes and Risks Associated with Ring Main Units Planned Inspection and Maintenance Practices for Ring Main Units Asset Renewal Program Sectionalisers Failure Modes and Risks Associated with Sectionalisers Planned Inspection & Maintenance Practices for Sectionalisers Asset Renewal Program Capacitors Failure Modes and Risks Associated with Capacitors Planned Inspection & Maintenance Practices for Capacitors Asset Renewal Program Zone Substation Transformers Failure Modes and Risks Associated with Zone Substation Transformers Planned Inspection and Maintenance Practices for Zone Substation Transformers Asset Renewal Program Circuit Breakers Failure Modes and Risks Associated with Circuit Breakers Planned Inspection and Maintenance Practices for Circuit Breakers Asset Renewal Program Zone Substation Structures Failure Modes and Risks Associated with Zone Substation Structures Planned Inspection and Maintenance Practices for Zone Substation Structures Asset Renewal Program Zone Substation DC Systems Failure Modes and Risks Associated with Zone Substation DC Systems Planned Inspection & Maintenance Practices for Zone Substation DC Systems Asset Renewal Program Zone Substation Protection Failure Modes and Risks Associated with Zone Substation Protection Planned Inspection and Maintenance Practices for Zone Substation Protection Asset Renewal Program Zone Substation Grounds and Buildings Failure Modes and Risks Associated with Zone Substation Grounds and Buildings Planned Inspection and Maintenance Practices for Zone Substation Grounds and Buildings Asset Renewal Program Customer Service Pillars Failure Modes and Risks Associated with Customer Service Pillars

179 LIFE CYCLE ASSET MANAGEMENT Planned Inspection and Maintenance Practices for Customer Service Pillars Asset Renewal Program Earth installations Failure Modes and Risks Associated with Earth Installations Planned Inspection and Maintenance Practices for Earth Installations Asset Renewal Program SCADA and Communications Failure Modes and Risks Associated with SCADA and Communications Planned Inspection and Maintenance Practices for SCADA and Communications Asset Renewal Program Load Control Plant Failure Modes and Risks Associated with Load Control Plant Planned Inspection and Maintenance Practices for Load Control Plant Asset Renewal Program Total Maintenance and Renewal Expenditure Forecast Maintenance Driven Expenditure Maintenance Driven Capital Expenditure Forecast

180 LIFE CYCLE ASSET MANAGEMENT 6 Lifecycle Asset Management This section of the AMP outlines Top Energy s maintenance and renewals policies, strategies and practices. TEN uses these to ensure that assets are utilised efficiently during their service life. 6.1 Maintenance and Renewal Planning Criteria and Assumptions Maintenance and Renewal Criteria The overall objective of Top Energy s asset management practices is to deliver the agreed level of service whilst achieving the lowest possible lifecycle cost for its assets. This means that the initial costs, the maintenance costs, any mid-life refurbishment and end of life replacement costs need to be considered holistically to achieve the best outcome. A risk-based approach is adopted to ensure that the required level of service is delivered. Risk exposure is managed through: an annual review of the risk management plan and implementing risk mitigation measures where risk exposure is incompatible with corporate risk policy, and undertaking performance and condition monitoring of critical assets. Economic analysis is undertaken for significant decisions related to lifecycle optimisation (e.g. operations, planned/reactive maintenance, renewals) and prioritisation of projects required to mitigate unacceptable risks. Top Energy has introduced a focus on the continuous improvement of asset management practices, processes, systems and plans in accordance with the improvement plan, which will be reviewed annually Top Energy s life cycle expenditure is split into four different categories. These are: Planned Maintenance: Routine and Preventative Maintenance TEN operates a time-based asset inspection and maintenance programme, whereby all assets are regularly inspected to identify defects that require repair. This routine inspection programme includes non-invasive condition assessments that are implemented on a regular time-based cycle to identify faults in key assets that cannot be identified by visual inspection. It also includes maintenance activities, such as vegetation management, which are undertaken on a time based cycle and are considered necessary to maintain the reliability of the network and to ensure that assets continue to function as designed. Renewal Maintenance Condition-based maintenance is based on an assessment of an asset s physical condition and is usually triggered by the findings of the routine inspection and condition assessment programmes. TEN s renewal maintenance philosophy entails performing maintenance only when safety, reliability and performance are compromised. The objective of the renewal maintenance programme is the prevention of unplanned faults by making optimal use of maintenance resources and maximising the operational and economic life of network assets. While age does not directly determine the need for the renewal maintenance of a particular asset, the age profiles of different asset categories are used to assist TEN to assess and budget forward renewal maintenance and asset replacement requirements. Reactive Maintenance This covers fault, near fault and high risk situations where an asset requires immediate or urgent attention. These activities are not planned in advance and are driven by asset failure, due to third party interference, foreign interference, storm events or sudden component failure. Budgeting for this activity is generally based on actual reactive maintenance costs in previous years. Capital Replacement Replacement of network assets is necessary, when continuing to maintain an existing asset is no longer cost-effective. Long-term renewal forecasting is based upon condition 178

181 LIFE CYCLE ASSET MANAGEMENT assessment and typical age replacement profiles for different asset classes. The renewal forecast will be refined with increasing use of probabilistic planning, as age at failure and age at renewal data is collected. Short-term renewal plans are based upon condition assessment. While asset replacement is generally managed as a maintenance activity (except for very large assets such as power transformers), asset replacement costs are treated as capital expenditure in accordance with generally accepted accounting principles Routine and Preventative Maintenance Programme Top Energy implements a routine inspection and maintenance program to ensure network safety and reliability. This strategy uses the assets criticality, serviceability, safety, performance, economic viability and the environmental consequences of failure to justify this expenditure. The Figure below illustrates this program. The frequencies indicated represent the maximum time between inspection and it should be noted that some assets are subjected to multiple inspections at differing frequencies. This results in assets being visited more often than the frequencies would indicate. GROUP ASSET VOLTAGE TYPE Field Equipment Poles/Conductors/Cables 33kV Annual 22kV 5 Year Pole Mounted Transformer 22kV 2 Year Ground Mounted Transformer 22kV 2 Year Switchgear - Pole Mounted 33kV 2 Year Switchgear - Ground Mounted 22kV 2 Year Regulator 22kV Annual Capacitors 22kV 2 Year Service/Link Pillars 400V 3 Year Earths 33kV 2 Year Substation Equipment Buildings Substation Monthly Equipment (Generic) Substation Monthly No Break Power Systems Substation 6 Monthly Transformer 33kV Annual Switchgear/Bus 33kV 4 Year Earths 33kV 6 Monthly Protection 33kV 4 Year SCADA and Communications Radio Repeater Communications Annual Substation Equipment Communications 2 Year Field Equipment Communications 3 Year Vegetation Management Pole Mounted Assets 33kV Annual Figure 131: 22kV 3 Year Ground Mounted Assets 33kV Annual TEN asset inspection programme Top Energy has contracted specialist field inspectors to implement this programme. These inspectors carry out detailed inspection tailored to the maintenance strategies of the different asset groups and types. They use a wide array of modern devices and proven practices to provide consistent condition 179

182 LIFE CYCLE ASSET MANAGEMENT assessments and ensure accurate records are maintained. With the GIS able to provide accurate asset information, the field inspectors can easily locate and identify each unique network asset in the field. They can then provide up to date attribute and condition information in electronic form to the GIS and the asset management database. The quality of the asset condition reported from inspections is proving to be of a good standard. It is anticipated that the quality of the data will improve over time, with experience and continuous improvement to methodology. Asset condition is rated and remediation planned, as summarised in Figure 64. This programme includes vegetation management and a condition monitoring program for key assets, which includes oil sampling of zone substation transformers and other programs, such as thermographic surveys Renewal Maintenance Programme Top Energy implements a renewal maintenance program to ensure network safety and reliability. This strategy uses the assets criticality, serviceability, safety, performance, economic viability and the environmental consequences of failure to justify this expenditure. Both age and condition are considered in determining the timing of treatment, but the latter is given priority. This condition-based maintenance is driven out of the preventative maintenance program. Condition information of each asset logged in the asset management database. This information is assessed and maintenance is scheduled based on the priority assigned during the assets inspection. The asset management database is checked periodically to ensure that action is taken within the specified timeframes. Work is then packaged and a final assessment is carried out to ensure that the original assessments were accurate and that the remedial action is still valid. Figure 64 below shows the information flow chart for condition-based maintenance planning. TEN is now actively investigating proprietary asset management systems and is planning to purchase and implement a new system in FYE Once implemented, the results of asset inspections will be recorded in the new asset management system and, over time, it is anticipated that this will allow more efficient and effective renewal maintenance programmes and schedules to be prepared. 180

183 Work Planning As Builds Fault Remediation Remediation Complete LIFE CYCLE ASSET MANAGEMENT Fault System Urgent Defects Top Energy Customer Urgent Defects Defects Enqueries Preventative Maintenance Lines Inspectors Defects Asset Management System System Update GIS System Data Verification As Builds Field Crew Project Drawings Maintenance Budget Update Network Maintenance Maintenance Budget Forecast Asset Remediation Remediation Complete Asset Management Plan Figure 132 Information flow chart condition-based assessment Reactive Maintenance Top Energy maintains a 24 hour fault service providing prompt and effective response to asset failures and civil emergencies. Due to the dispersed nature of the network and the impracticality of constantly monitoring every aspect of the network, it is likely that problems will be detected outside of the preventative maintenance inspections. If left unchecked, these conditions could have serious consequences. Therefore, it is a requirement that employees report network condition issues regardless of the task being undertaken and the public are encouraged to do the same. Asset conditions reported outside of preventative maintenance are rated as summarised in Figure 133 and the appropriate action is taken Asset Replacement The general strategy for the replacement of assets is to consider the following justifications: Risk: The risk of failure and associated impacts justifies action (e.g. cost implications, impact and extent of supply discontinuation, probable extent of environmental damage, health and safety risk). Asset performance: Renewal of an asset when it fails to meet the required level of service. Non-performing assets are identified by the monitoring of asset reliability, capacity and efficiency during planned maintenance inspections and operational activity. Economics: It is no longer economic to continue repairing the asset (i.e. the annual cost of repairs exceeds the annualised cost of renewal). The Figure below is summarised from C S Network Asset Remedial Management Network. 181

184 LIFE CYCLE ASSET MANAGEMENT PRIORITY ISSUE RESPONSE TIME X Very High Critical Fault or near fault A High Urgent Unplanned, end of life B Medium Routine Planned, end of life C Low Monitor Approaching end of life D Very Low Passive No operational impact Remediate within 48 hours. Remediate within 3 months. Remediate within 12 months. No remediation timeframe. Monitor condition. No remediation timeframe. May be left indefinitely. Figure 133: Response priority definitions The assumptions are: Hazard mitigation: Equipment will be maintained, labelled, fit for purpose and secured to eliminate, or reduce to acceptable levels, hazards to staff, the public and the environment. Reliability: Equipment will be maintained to mitigate the risks associated with the failure of any given component to ensure that the required service reliability standards are achieved. Operation: Equipment will be maintained and used in a way that it was designed for. Regulatory requirements: Maintenance (e.g. vegetation clearances, voltage compliance) will be undertaken to ensure regulatory compliance. Life span: Equipment will be installed, operated and maintained in a way that allows its full economic life to be achieved. Renewal: Assets will be renewed when no longer able to function with sufficient economy, reliability or capacity (the ability of an asset to cope with expected load growth). The renewal programmes will reflect the overall condition profile of network assets. Line renewals will also reflect the suitability of line route for on-going maintenance and operation, The opportunity to mitigate the effect of failure by alternative means such as the use of line isolating, sectionalising, automation equipment or non-network solutions such as mobile generators will be considered. 6.2 Transmission Assets As noted previously in this plan, Transpower s Kaikohe and Kaitaia 110kV substations and the 110kV Kaikohe-Kaitaia transmission line on 1 April 2012 will transfer to Top Energy, which will assume responsibility for the maintenance of these assets as at that date. Prior to the purchase, TEN s maintenance manager will liaise with Transpower s maintenance personnel and develop a maintenance plan for looking after these assets. This will be described in more detail in the 2013 AMP. It is anticipated that the first year of ownership will largely be one of familiarisation, as TEN and Top Energy Contracting Services (TECS) staff gain a better understanding of the assets installed and their condition. This will include a helicopter inspection of the transmission line and a thermal imaging survey of the conductors at both substations. As noted in chapter 5, the 33kV switchyard at Kaikohe will be moved indoors during FYE 2014 and the two 110/33kV transformers at Kaitaia will be replaced with 40/60 MVA units the following year. Top Energy is also planning a refurbishment of the transmission line after completion of the new 110kV line 182

185 LIFE CYCLE ASSET MANAGEMENT between Wiroa and Kaitaia in FYE This is expected to be a major undertaking that will take up to four years. 6.3 Overhead Conductors Failure Modes and Risks Associated with Overhead Conductors Failures and tripping by conductor failure occur mostly due to: vegetation interference, animal interference, vehicular interference, such as cranes, excavators and farm equipment working in the vicinity, insulator failure, tension and non-tension connection failure, retention device failure, such as binder, dead end and armour rod, corrosion in coastal and geothermal environs, and human interference, such as foreign objects thrown into lines or trees felled through lines. Many of these have strategies in place to minimise the occurrences. However areas of concern are pencil connectors and No.8 wire conductor. Pencil connectors are grease filled aluminium sleeves used as a bimetal connector. These have oxidised over time causing LV and HV connection failures. A program to eliminate these connectors is being implemented. No.8 fencing wire has been used historically for emergency conductor repair. Although this practice has ceased, it is now causing problems due to corrosion. Fencing wire is being replaced as it is found, however there are no records of its use and thus it is difficult to locate and identify Planned Inspection & Maintenance Practices for Overhead Conductors The inspection schedule currently in place for overhead conductors is as follows: Condition Assessment Structures Sub-transmission, distribution and low voltage support structures are visually inspected on a three year cycle. Condition Assessment Conductors Ground-based visual inspection of sub transmission, distribution and low voltage conductors are done on a three year cycle. Thermal imaging of sub transmission lines is conducted annually and six-yearly for distribution conductors. Helicopter-based inspection of sub-transmission lines is conducted sixyearly, supplemented by the occasional inspections initiated for fault or operational reasons. Vegetation Assessment Sub transmission conductors are patrolled annually whilst distribution and low voltage conductors are patrolled on a three year cycle. Identified problems are recorded and repairs made in accordance with the processes identified in Section 6.1. Future maintenance workloads are projected using an analytical model. The assessed condition of each asset is prioritised based upon condition criteria, which in turn is used to schedule maintenance and replacement. The financial forecast for operations and maintenance activities to asset level is detailed in sections 6.2 to 6.21 and Section

186 6.3.3 Vegetation Strategy LIFE CYCLE ASSET MANAGEMENT Vegetation management has always been a part of the work that Top Energy has been directly involved with. The clearing of vegetation in proximity to lines is critical to both network reliability and public safety. The Electricity (Hazards from Trees) Regulations 2003 came into force in early This provides a framework of requirements and responsibilities to mitigate problematic trees within the proximity of power lines and bolsters Top Energy s existing vegetation management strategy. Initial tree trimming/removal costs are born by Top Energy, but as the tree owners are identified and the compulsory first cut and trim on the tree is complete, the on-going maintenance is be passed to the tree owner. It is Top Energy s preference to remove trees where practical and economic to do so, to minimise on-going maintenance cost and risk. Top Energy will continue to maintain a perpetual program to assess and mitigate tree interference, as new trees grow and existing trees re-grow into power lines. Figure 134 below demonstrates a steadily increasing trend in overall network vegetation related faults until 2009 and the impact of the vegetation management programme that commenced in FYE In 2011, there were a total of 55 vegetation-related faults that contributed 10.4% of the total SAIDI Vegetation Interruptions Figure 134 Vegetation Interruption Count Regulatory Compliance The most onerous requirement under the Electricity (Hazards from Trees) Regulations 2003 is to maintain records of all trees that grow into our lines and the course of action taken. This must be done throughout the entire life of the tree and for any new tree that should grow into the power lines. Historically this has not been done. Top Energy now stores this information in the Vegetation Management Application (VMA). This system is overlaid with GIS to record geographically the location of trees that pose a risk to overhead lines, the tree cutting work done on each recorded tree and the details of the owner of each tree Far North District Council (FNDC) Relationship The FNDC has a significant numbers of trees that affect Top Energy s power lines. Top Energy has an informal relationship with the FNDC that allows Top Energy to trim trees that are encroaching statutory clearance distances. However, this informal agreement is becoming unworkable as the District Plan evolves, making resource consent necessary for tree trimming activities. It would ultimately be in Top Energy s best interest for vegetation to be completely removed at ground level. Application of the Electricity (Hazards from Trees) Regulations 2003 would place the onus onto the FNDC to effectively manage its own tree population after the first cut/trim by Top Energy. Top Energy is currently in negotiation with the FNDC to progress this initiative. 184

187 Targeted Cutting Strategy LIFE CYCLE ASSET MANAGEMENT The three year vegetation management programme that commenced in FYE 2010 will be completed in FYE In FYE 2013, it is planned to reduce expenditure on vegetation management to $2.18 million. The strategy will include: a full assessment of the vegetation issues impacting the 110kV transmission line and the development of a prioritized vegetation management program. Tress encroaching the growth limit zone defined in the Electricity (Hazards from Trees) Regulations 2003 will be trimmed clear of the zone, an inspection of all 33kV lines with action taken to ensure that all trees remain outside the notice zone, as defined in the Regulations, an inspection of all 11kV lines to manage any trees that constitute an immediate hazard to conductors, and a management program targeting six feeders, to ensure that trees remain outside the notice zone as defined in the Regulations. The feeders have been selected on the basis of their contribution to network SAIDI. The figure below shows the information flows used to manage the vegetation control programme. Investigation Top Energy Enqueries Customer Electricity (Hazards from Trees) Regulations 2003 Vegetation Liaison Officer Tree Hazard Vegetation Management System Work Planning System Update Asset Management Plan Vegetation Budget Update Vegetation Budget Forecast Network Maintenance Audit Progress Report Vegetation Crew Figure 135 Information Flow Vegetation Control 6.4 Poles and Structures Failure Modes and Risks Associated with poles and structures Failures from wooden cross arms involve failure of the cross arm itself or collapse of the mechanical support for insulators and/or cross arm. A wooden pole will degrade steadily over a long period of time and this degradation is not always immediately apparent. Degradation is dependent on many factors, such as tree species, timber treatment and ground conditions. Wooden poles can fail suddenly when loading on the pole is altered. Unassisted failure is possible. Failure due to climbing or reconfiguring conductors is rare, as poles are assessed prior to any work. Likely failure modes are either high winds or foreign interference, such as 185

188 LIFE CYCLE ASSET MANAGEMENT vehicles, falling trees or possibly even stock pushing on them. The majority of Top Energy s wooden poles are hardwood, treated pine and a few Larchwood. Top Energy has stopped the installation of wooden poles in favour of pre-stressed concrete. Wooden poles are therefore being phased off the network, the majority of which will be done in the next ten years. This will leave only the few most recently installed wooden poles behind. A concrete pole will degrade extremely slowly and therefore maintain consistency of condition throughout its life. Changes in manufacturing techniques and quality control of this process are producing superior poles. Some environmental conditions can affect concrete poles such as coastal or sulphurous areas, which are both present within the Top Energy region. Concrete poles can fail suddenly when loading on the pole is altered. Unassisted failure is improbable. Failure due to climbing or reconfiguring conductors is rare, as poles are assessed prior to any work. Likely failure modes are either high winds or foreign interference such as falling trees or constant chipping/cracking from intermittent contact with heavy mowers, farm equipment, low speed vehicles, etc. Early concrete poles were manufactured internally by Top Energy. The oldest of these are now over sixty years old are beginning to spall exposing the reinforcing. Some poles have stay wires to assist with their loading and these stay wires are connected to ground anchors. Stays and anchors may deteriorate and this, if not identified and remedied through regular inspection and maintenance, could result in pole failure. All structures within, or close to, the road reserve are subject to the risk of vehicle impact. Poles in off road locations are subject to the very low risk of vehicle impact from farm equipment, erosion and movement by stock. The consequences of all of the above modes of failure are live conductors on the ground, low conductors or power outages Planned Inspection & Maintenance Practices for Poles and Structures The inspection schedule currently in place for poles and practices is as following: Ground Based Inspection Ground based inspection of sub-transmission poles and structures is conducted annually and, for the distribution network, five-yearly. Thermal imaging and a radio frequency discharge detector are utilised on the sub-transmission circuit to assess the condition of each insulator and connection. Hazardous poles are identified and tagged for priority attention and recorded in the asset management database. At present, TEN uses traditional methods of condition assessment for wooden poles, i.e. a visual inspection together with a hit with a hammer/aural test for rot. This is done in association with digging the ground out around the air/soil interface to allow a visual/probe inspection. Concrete poles are inspected visually for exposed rebar and possible degradation of the concrete. More sophisticated condition monitoring methods, such as ultra sonic density measurements or micro-drilling for wooden poles are available, but not currently used. Pole-Top Inspection: The combination of periodic ground based and aerial inspection is considered sufficient at present and specific pole-top inspections are not normally carried out unless other work is being executed on the pole. Identified problems are recorded and repairs auctioned in accordance with the processes identified in Section Asset Renewal Programme Top Energy implements a programme to replace poles that are no longer considered fit for service. 186

189 LIFE CYCLE ASSET MANAGEMENT Top Energy s strategy is to optimise the maintenance expenditure on cross arm replacement. To this end, the complete pole is replaced whenever a wooden cross arm requires replacement on an old pole that itself would be replaced in less than seven years. This is because it is not-cost effective to replace only the cross arm where less than seven years of service is expected from the pole. Hardwood poles are presently being renewed at the rate of about 10% per year. The pole age profile implies that the renewal rate will gradually increase over the next 20 years and then decline again. 6.5 Underground & Submarine Cables Failure Modes and Risks Associated with Underground & Submarine Cables The main cause of failure in cables is third-party damage, usually caused by an excavator or directional drill. In the case of submarine cables, damage is usually due to anchor strike. TEN offers a free cable location service to encourage people to reduce this risk. It also has a process to manage the activities of people working near cables, when it is aware of the activity. Submarine cables are marked on the shore line and appear on nautical charts. The failure of a cable usually results in an outage to customers. The risks from explosion or contact are considered low, as the cables are buried and such an event would normally be associated with a dig-in. The loss of supply associated with a damaged cable usually takes longer to alleviate than an overhead incident. This is due to the repair time involved. For HV cables, failure of a cable termination or joint is much more likely than electrical failure of the cable itself. On-going failure of HV cable terminations has prompted an investigation of terminations for partial discharge (PD) and transient earth voltages (TEV). The result of this investigation has revealed poor construction techniques leading to premature failure. PD and TEV monitoring of cable terminations is now a part of the preventative maintenance program to mitigate potential costly faults. For XLPE cables, the mechanisms of insulation deterioration leading to failure are now well understood. The latest information on the condition of cables installed in other parts of New Zealand is monitored regularly to help identify any areas of risk for Top Energy. Low voltage cables are predominantly single core double insulated aluminium. These are looped into service pillars and lugged onto a piece of paxolin board. This system is unsealed, allowing water ingress. It is not uncommon to find during inspection that the aluminium cable around the lug is badly, and in some cases, completely oxidised through. All new installations will be four core aluminium cables utilising a completely sealed system. Existing installations will be changed over to the sealed system as prone areas are identified and as age and condition dictate Planned Inspection & Maintenance Practices for Underground & Submarine Cables As these assets are buried, it is not possible to carry out a general visual inspection of their condition. However, where they are terminated onto other plant (e.g. switchgear), they can be seen and are included as part of the condition inspection for that item. Maintenance testing is five-yearly on-line PD mapping of all 11kV and 33kV cables entering zone substations. Submarine cables are tested five-yearly and a submarine inspection is carried out every ten years. The basic approach to ensuring long life for cables is to ensure they are carefully installed and appropriate tests are carried out to confirm this has happened. When commissioning all cables (apart from very short lengths (i.e. <=15m), specific tests like polarisation index (PI), 5kV step voltage (SV), temperature corrected sheath integrity and very low frequency high potential (VLF high pot) tests are carried out. 187

190 LIFE CYCLE ASSET MANAGEMENT For faulted cables, TEN carries out controlled DC impulse testing during fault location, and post repair, PI, SV and sheath integrity tests are carried out. A decision to repair or replace the cable is dependent on the cost and practicality of repairing the cable. Temporary repairs are generally made to restore power which is then followed up with a cable replacement where required Asset Renewal Program As a general principle, cable replacement planning is based on reliability or load growth. As such, provisions have been made for cable replacement for unplanned outages. Top Energy s cable population is generally young and has a significant service life remaining. Accordingly, underground cables do not have a planned refurbishment programme. Replacement will occur when the cost of repairs become uneconomic. 6.6 Distribution and SWER Transformers Failure Modes and Risks Associated with Distribution and SWER Transformers The main causes of failure of distribution and SWER transformers are lightning, corrosion, over-loading and oil leaks. Top Energy is in the process of reducing the number of transformer failures resulting from lightning events by fitting lightning arrestors to all new pole mount transformers. The majority of Top Energy s customers live either on farmland or in coastal locations. Farmland tends to have a low density population, whereas coastal areas tend to have higher, though somewhat, seasonal population. As a consequence, many assets (including transformers) are located in coastal areas, exposing them to harsh coastal environments that results in premature aging. Overloading of transformers has historically occurred primarily due to growth, without proper consideration of transformer impacts when new connections are made. No new connections are now made without analysis of the loading that a new connection will have on a transformer and the impact that a new or larger transformer will have on the network. Transformers are constructed using mineral oil as an insulating and cooling medium. Unfortunately, this oil is an environmental hazard. There are alternative oils that are considered safer but come at a significant cost. Fortunately, leaks are relatively uncommon and when they do occur, it is usually just enough to stain the side of the transformer. Significant leaks are rare and unpredictable and thus the response is always reactive Planned Inspection and Maintenance Practices for Distribution and SWER Transformers Distribution transformers are inspected three-yearly. In addition to the normal condition monitoring inspections, all ground mounted transformers are inspected annually for safety. As part of this inspection process, minor maintenance work is undertaken, such as replacing any missing padlocks and clearing any vegetation from inside the cubicles. An inspection sheet is prepared, noting conditions such as corrosion, oil leakage, missing base plates, this is processed in the same way as the normal condition assessment process. Generally, modern distribution transformers have minimal maintenance requirements. Older units with signs of significant degradation or damage are replaced and the old unit is refurbished if viable or scrapped. 188

191 6.6.3 Asset Renewal Program LIFE CYCLE ASSET MANAGEMENT Top Energy has a large quantity of transformers at the end of their service life, often located in remote areas. As the failure rate of these units is relatively low, the most effective practice is to replace on failure. In some circumstances it may be appropriate to change units in association with other planned work in the area. A minimum stock holding of critical spare transformers is maintained accordingly. Significant quantities of transformers have been identified as being overloaded. This leads to reduced life and performance. These transformers will be profiled and a program of balancing, reconfiguration and, if necessary, upgrading will be implemented. New distribution transformer units are hermetically sealed for life and factory fitted with surge arresters. Tanks have additional corrosion protection measures provided. 6.7 Auto-Reclosers Failure Modes and Risks Associated with Auto-Reclosers The main causes of failure of auto-reclosers are electronic controller failures. Moisture ingress and oil contamination has led to catastrophic failure causing oil to vent from the failed unit. This is an environmental hazard and is costly to clean up. Personal risk of injury is very low Planned Inspection and Maintenance Practices for Auto-Reclosers Auto-reclosers have a two-yearly inspection program covering electronic controller checks and an external visual inspection. Diagnostic data and operational settings are also captured at the same time. In addition there is a six-yearly battery replacement program in place. Maintenance of the interrupter assembly and oil replacement is based on a variety of regimes dependent upon the model. These are variously based on aggregated fault duty and number of mechanical operations Asset Renewal Program A significant proportion of auto-reclosers are relatively new consisting of SF 6 and vacuum units. There are few oil filled auto-reclosers left in operation. These oil filled units are being phased out, with the last few likely to be replaced within the next three years with resin encased vacuum units. 6.8 Regulators Failure Modes and Risks Associated with Regulators The main causes of failure of regulators are electronic controller failures and mechanical failure of the tap changer. Corrosion specifically around the lid, bushing and control box allowing water and contamination to enter is also a problem Planned Inspection and Maintenance Practices for Regulators Regulators are inspected at two-yearly intervals, or at 50,000 operations, whichever is first. This includes general overall site inspection as well as local control operation. At four year intervals or 100,000 operations, whichever is first, the regulators are returned to the workshop for complete servicing after being replaced with fully-serviced units. 189

192 6.8.3 Asset Renewal Program LIFE CYCLE ASSET MANAGEMENT Due to the limited population, there are currently no renewal programmes in place for these assets. Individual asset replacement will be as a result of specific condition inspection. Should this reveal a systemic issue with the asset, a renewal programme may then be developed for this asset class. 6.9 Ring Main Units (RMU) Failure Modes and Risks Associated with Ring Main Units The main causes of failure of RMUs within the Top Energy geographical area is third-party vehicle accidents. This is followed by corrosion due to harsh coastal conditions Planned Inspection and Maintenance Practices for Ring Main Units RMUs are included as part of the routine condition assessment regime. Routine oil testing occurs once every five years, with a partial discharge test of the cable terminations on an annual basis. Routine inspection includes a yearly hazard inspection and visual condition assessment Asset Renewal Program A significant proportion of Ring Main Units are relatively new. There is no specific program for renewal at this stage, though our oldest unit has been scheduled for replacement in 2010/ Sectionalisers Failure Modes and Risks Associated with Sectionalisers The main causes of failure of sectionalisers are lightning and sudden mechanical failure Planned Inspection & Maintenance Practices for Sectionalisers Oil filled sectionalisers have a two yearly external visual inspection. After 100,000 operations or four years service, the sectionaliser is replaced with a fully-serviced unit and it is returned to the workshop for servicing and testing. New link type air insulated sectionalisers have a two-yearly visual inspection. These units are completely replaced if there is any doubt in their operation Asset Renewal Program The majority of sectionalisers were installed within the last five years whilst the remaining units are being monitored. There is no program for renewal at this time Capacitors Failure Modes and Risks Associated with Capacitors The main causes of failure of capacitors are lightning and sudden mechanical failure. 190

193 Planned Inspection & Maintenance Practices for Capacitors LIFE CYCLE ASSET MANAGEMENT They are included as part of the condition monitoring regime and are inspected from the ground on a two yearly cycle, to examine for signs of deterioration. These include: leakage, cracked insulators, bulging tank, flash-over carbon marks, and tank rupture Asset Renewal Program There are currently no renewal programmes in place for this asset, but individual replacement will be as a result of specific condition inspection Zone Substation Transformers Failure Modes and Risks Associated with Zone Substation Transformers There are environmental risks associated with zone substation transformers, as they contain significant quantities of insulating oil. All zone substation transformers have been tested for PCB, but none has been found. This risk becomes even higher with the mobile transformer. To minimise environmental risk due to accidental spills during transportation, this substation uses biodegradable vegetable oil. All zone substations have oil management systems on site and some have oil interception facilities in their ground water systems. There are oil management systems at depots and clean up equipment is kept ready in case of accidental spillage. The risk of transformer failure is primarily managed through the comprehensive condition based maintenance and protection regime. The risk from seismic activity is low in the Top Energy area and the transformers and auxiliaries have been appropriately secured. Lightning arresters are provided to address the issue of lightning strike. These may not necessarily protect the substation against a direct lightning strike, however, based on a risk analysis, the substantial costs of upgrading to provide such protection is considered prohibitive Planned Inspection and Maintenance Practices for Zone Substation Transformers An annual programme of dissolved gas analysis (DGA), as well as monthly, yearly, and five-yearly major inspections is undertaken based on accepted international best practice. Each year, a radio frequency discharge detector is used to observe the condition of transformer connection bushings. A five-yearly infra-red thermography programme is undertaken on each switchyard, which includes monitoring the transformers and auxiliaries. Top Energy undertakes its own interpretation of oil test data and has built a spread sheet programme to assist in this. Levels, limits, and rates of total dissolved combustible gases (TDCG) and individual gases (key gases) outlined in IEC are the first indicators of an incipient problem. In the event of any concern arising, an increased monitoring programme is implemented. If necessary, a remedial action plan will be developed taking also into account: IEEE Standard C (the prescriptive method is ascertained as one of the inputs to final decision of the course of action), 191

194 Rogers Ratios (invoked only when gas levels reach a certain level), and other tests, condition assessment, history, circumstances, age and design. LIFE CYCLE ASSET MANAGEMENT The IEEE C , Guide for Failure Investigation, Documentation and Analysis for Power Transformers and Shunt Reactors and IEEE Std Guide for Diagnostic Field Testing of Electric Power Apparatus - Part 1 Oil Filled Power Transformers, Regulators and Reactors are followed. Silica gel maintenance is rigorous. The crystals are recharged by a thorough oven dry-out before canisters reach a 50% level, as required during the monthly station inspections. While silica gel desiccant systems are not perfect, they are sufficient for Top Energy s needs. Alternative refrigeration principle (e.g. Drycol) and pumped filtration systems (e.g. Drykeep) have been assessed, but are presently not considered necessary. Instead, silica gel plus oil refurbishment (as required) will continue to be undertaken. Oil is refurbished or reclaimed based on oil quality tests. Units are streamline filtered depending upon moisture content (%DW) and level of saturation, in accordance with the IEEE standard. Secondary indicators of this are voltage breakdown and dissipation factor. The decision to streamline filter with oil treatment by Fuller s earth is made where there are indications of sludging or is triggered by acidity and interface tension (IFT) measurements. Mid-life refurbishment by means of a major overhaul, including insulation dry out and magnetic circuit core clamp re-tightening, is undertaken based on condition assessment (including a visual assessment of likely moisture ingress sites corrosion, explosion vent condition, seal conditions, radiator condition) and the detailed diagnostics noted above. It is not undertaken automatically based on age. With thorough transformer maintenance and monitoring programme, it should be possible to avoid or delay the need for such a major invasive maintenance action. The overall condition of TEN s zone substation transformers is above average, according to current oil test, with the current primary condition concerns being minor oil leaks. Inspections and investigations are on-going to identify oil leaks as soon as they occur, with any remedial action instigated immediately or incorporated into the annual maintenance plan. Old-style earthquake restraints comprising of welded wheels bolted to rail tracks are of concern, but the risk is considered low and earthquake restraints will be upgraded along with future bund upgrades. Zone substation tap-changers have their oil changed two-yearly. Parts are replaced or refurbished based on inspected conditions and manufacturer s recommendation per cyclometer reading (i.e. number of operations). Maintenance costs are being tracked, so that the option of adopting new technology by replacing existing oil filled tap-changers with vacuum type tap changers may be considered on a business case basis Asset Renewal Program There are currently no formal asset renewal programs in place for zone substation transformers. The transformer at Taipa Substation is to be upgraded to accommodate growth and the old transformer will be relocated to the Omanaia Substation to replace the three single phase transformers that are approaching end of life Circuit Breakers Failure Modes and Risks Associated with Circuit Breakers Circuit breakers fail most commonly as a result of ingress of moisture, loose connections and inadequate maintenance. Failure of a circuit breaker whilst it is being operated poses a significant risk to the operator. As a result, routine maintenance is carried out on all Top Energy circuit breaker classes. 192

195 Planned Inspection and Maintenance Practices for Circuit Breakers LIFE CYCLE ASSET MANAGEMENT Monthly site inspections and recording of cyclometer readings are undertaken. The maintenance program for circuit breakers is coordinated with maintenance of any associated transformer and protection to optimise maintenance work and minimise the risk of actual outages and overall costs. The following maintenance strategy has been adopted by Top Energy: 11 kv incomer and tie breakers are serviced four-yearly, 11 kv feeder vacuum indoor circuit breakers are serviced four-yearly, 11 kv feeder indoor or outdoor oil interrupter/oil insulated circuit breakers with/without electronic control are serviced two-yearly. This is done more frequently if the number of operations since last service is > 15, 33 kv vacuum interrupter/oil insulated are service four-yearly, 33 kv vacuum interrupter/air insulated are service four-yearly, and 33 kv minimum oil circuit breakers are serviced annually. These frequencies are increased if the cyclometer readings indicate high numbers of operations. Oil CB maintenance includes oil change, checking tabulators and contacts. Manufacturer s manual on lubrication and other tests are followed. Vacuum interrupters have gaps checked as per the manufacturer s recommendations. This technology, however, is relatively low maintenance. Twoyearly partial discharge testing occurs on all zone substation switchgear, including the metal clad VT/bus chamber switchgear Asset Renewal Program Circuit breakers that are considered to be beyond economic repair are programmed for replacement within a specific defined period. Circuit breakers are also replaced routinely as part of larger scale zone substation refurbishment programmes Zone Substation Structures Failure Modes and Risks Associated with Zone Substation Structures Zone substation structure can fail as a result of inadequate maintenance, animal intrusion and weather conditions, such as localised lightning strikes Planned Inspection and Maintenance Practices for Zone Substation Structures Top Energy s outdoor structures have a long life span. Their condition can be monitored visually and with the use of thermal imaging and partial discharge testing. Because of the critical nature of this equipment, they are individually checked for correct operation every two years and maintained if necessary Asset Renewal Program Pukenui Substation has recently undergone refurbishment, with the bus reconfigured to allow the mobile substation to be connected and obsolete switchgear replaced. Modern protection systems have been installed. Moerewa and Waipapa substations have been identified as needing attention and investigations will be undertaken as to the extent of refurbishment required. It is expected that the work will include the installation of indoor 11kV switchgear and will be completed around FYE

196 LIFE CYCLE ASSET MANAGEMENT 6.15 Zone Substation DC Systems Failure Modes and Risks Associated with Zone Substation DC Systems Zone substation DC systems generally fail as a result of animal (vermin) intrusion and failure of backup batteries or charging systems Planned Inspection & Maintenance Practices for Zone Substation DC Systems Routine inspection of all DC systems including voltage and current checks, charging system check, and visual condition checks are performed on a monthly basis Asset Renewal Program Due to the limited population, there are currently no renewal programmes in place for these assets. Individual asset replacement will be as a result of specific condition inspection. Should this reveal a systemic issue with the asset, a renewal programme may then be developed Zone Substation Protection Failure Modes and Risks Associated with Zone Substation Protection Failure of protection systems within a zone substation can lead to non-operation of circuit breakers, alarms and other safety devices. Protection systems generally fail due to poor local conditions, lightning activity and age Planned Inspection and Maintenance Practices for Zone Substation Protection Until an upgrade to numerical relays is commissioned, the present maintenance regime for all relays will continue as follows: functional tests, minor visual inspection of settings and condition will occur two-yearly, calibration tests will occur four-yearly, and more frequent testing than the above two-yearly functional and four-yearly calibration test regime will be considered for very old relays, where there is evidence of drift or degradation. The adoption of modern, microprocessor-based numerical relays will provide the opportunity to increase the interval of calibration testing beyond four years. Top Energy will continue to carry out CT and VT ratio checks five-yearly to check for drift that can occur due to core movement with resin type embedded construction Asset Renewal Program A major capital expenditure programme covering the entire Top Energy network is planned to address the current issues surrounding ageing and ineffective protection systems. The detailed renewal and replacement programme will be managed on a risk assessed basis. 194

197 LIFE CYCLE ASSET MANAGEMENT 6.17 Zone Substation Grounds and Buildings Failure Modes and Risks Associated with Zone Substation Grounds and Buildings The Omanaia Substation has been identified as being subject to flooding, if the drainage waterways near it become clogged. To manage this risk, the waterways are inspected monthly as part of the substation inspection and cleared as necessary, particularly after a major storm Planned Inspection and Maintenance Practices for Zone Substation Grounds and Buildings A 10-year building maintenance plan details requirements for yards, roofs, external walls, doors, windows, plumbing, electrical services and the interior. Buildings are serviced by contract cleaning staff on monthly intervals Asset Renewal Program Due to the limited population, there are currently no formal renewal programmes in place for these assets. Individual asset replacement will be as a result of specific condition inspection. Should this reveal a systemic issue with the asset, a renewal programme may then be developed for this asset class Customer Service Pillars Failure Modes and Risks Associated with Customer Service Pillars Failure of a pillar is commonly due to foreign interference or poor installation. Poor installation will lead to internal failure, resulting in loss of supply and internal damage. There is very little risk beyond this with the except for a neutral connection failure. Foreign interference by vehicle or vandalism can lead to live internal parts being exposed, which could result in personal injury Planned Inspection and Maintenance Practices for Customer Service Pillars All customer LV pillars are inspected at three-yearly intervals for hazardous conditions. During this condition assessment, minor maintenance is undertaken, such as replacing missing Allen key screws or removing grass growing up into the enclosure. This work is part of the condition monitoring process for field equipment. Low voltage cables supplying service pillars are terminated onto a piece of paxolin board. This board is prone to breaking, should the connection be over tightened, installed incorrectly or subject to any form of impact. This may result in the bare lugs inside shorting leading to loss of supply. Care must be taken when opening a service pillar, as any movement could cause bare lugs on a broken paxolin board to short. When these are identified the paxolin board is removed and GelPorts are installed. These are sealed units that provide waterproofing and protection against incidental contact. Service pillar fuse bases are a constant source of failure commonly due to loose connection into the fuse base. This can result from poor installation, vehicular vibration or any form of impact. TEN has recently introduced the use of a sealed service fuse base incorporating the use of a shear off bolted insulation piercing connection. The shear off connection ensures that the connection is correctly tightened and should eliminate the on-going issue of failure from poor connections. Being a sealed unit, these units also provide waterproofing and protection against incidental contact. 195

198 Forecasted Earth Remediation Budget Update Earth Remediation Budget Asset Renewal Program LIFE CYCLE ASSET MANAGEMENT Pillars are not complex assets. As long as the enclosure remains intact, components could be replaced indefinitely. There are a few remaining fibreglass pillars that are replaced upon discovery due to the fibreglass deteriorating. These have only survived replacement to date due to misidentification. Pillars are replaced when they can no longer be secured or when repairs are not economical Earth installations Failure Modes and Risks Associated with Earth Installations Failure of an earth installation can be from a variety of sources such as: vandalism, foreign interference, environmental and obsolete installation standards. This is identified through visual inspection and testing. The risks associated with an earth installation not functioning correctly are primarily protection systems not working and earth potential rise. Either one of these scenarios can lead to injury or damage to persons or property Planned Inspection and Maintenance Practices for Earth Installations Distribution equipment earths are tested three yearly whereas zone substation earth mats are tested annually. Since 2006, Top Energy has managed touch and step potential issues according to a risk assessment approach based on the NZECP 35, and taking into account the circuit distance from the nearest zone substation and the assessed frequency of people in the vicinity. As this has resulted in a requirement for higher quality earthing than previously used, a significant amount of remedial work is required. Remedial work identified is prioritised to focus on those areas with the highest frequency of people (i.e. shopping areas, schools). The flow chart below outlines the inspection and planning process. The figure below shows the information flow chart for earth testing and remediation. Lines Inspectors Asset Management Plan Earth Test Geographic Information System Earthing Data Test within acceptable parameters? NO Schedule Remediation YES Update GIS Remediation Complete Field Crew Earth Remediation Figure 136 Information flow chart earth testing and remediation 196

199 Asset Renewal Program LIFE CYCLE ASSET MANAGEMENT Earth systems for distribution equipment have historically been very simplistic and reviews of earthing practices have shown some inadequacy. TEN s earthing standards have been therefore revised and aligned with best industry practice. This, in conjunction with regular inspections, has revealed that significant investment is necessary to improve system reliability and safety. Earth systems with high earth resistance test readings and below standard construction in high risk areas will be targeted first. The remainder will be systematically upgraded SCADA and Communications Failure Modes and Risks Associated with SCADA and Communications SCADA systems can fail for a number of reasons, including: telecommunications, supply availability, relay failure and server failure. Failure of the SCADA system, although recoverable, leaves the control room operators without an active view of the network. Careful recovery plans are then instigated to manage the situation Planned Inspection and Maintenance Practices for SCADA and Communications Recent installations of new Foxboro & Schweitzer Engineering remote terminals and associated Ethernet communications equipment, combined with the decommissioning and removal of legacy remote terminal units and radio systems, has prompted a review of the maintenance strategy. The installation of this new equipment with its on board diagnostics information has made it easier to monitor the systems and alarm the network assets for operation outside of normal parameters. At two-yearly intervals, all analogue transducers and remote terminal inputs are checked, recorded, and adjusted if necessary, and power supplies are checked at the master station and all remote terminals. At 12-monthly intervals, all VHF and UHF radio sites are visited. The operational levels are checked, recorded and adjusted if necessary. All aerials and power supplies, along with site security and accessibility, are also checked and rectified as necessary. At four-yearly intervals, a more detailed inspection of aerials and equipment is undertaken and major operational adjustments made if necessary. Central zone substation remote alarms are checked on a monthly basis, from a common alarm test facility at each remote site. The master station systems (hardware and software) are inspected annually by the system vendor under a support contract to ensure they are operating to the appropriate levels of service. Minor server maintenance is handled as required by SCADA support staff in conjunction with IT. With the installation of optical fibre communications, responsibilities and standards need to be defined for the safe and optimum operation and maintenance of this media. These systems will be developed in conjunction with external specialist consultants Asset Renewal Program There are currently no renewal programmes in place for the Top Energy SCADA system. 197

200 LIFE CYCLE ASSET MANAGEMENT 6.21 Load Control Plant Failure Modes and Risks Associated with Load Control Plant Failure of load control plant can result in Top energy breaching its maximum permitted peak load capacity at the Kaikohe and Kaitaia GXP s. This could also result in the overload of certain highly loaded sections of the Top Energy network. The risks to the plant are mitigated by: operating plant within its limits, having a limited number of critical spare parts immediately available, and holding a support contract with the system vendor, including access to specialist parts if required Planned Inspection and Maintenance Practices for Load Control Plant The maintenance regime for this plant involves their daily functional use. Ripple plant equipment and load control software systems are visually inspected and operationally tested on a monthly basis. There is also a detailed annual inspection by the system vendor under the terms of an annual support contract. Maintenance or adjustments to the systems arising from vendor inspection reports are then programmed to be carried out at the earliest convenient opportunity Asset Renewal Program Waipapa substation is currently the only ripple plant scheduled for renewal during the planning period. 198

201 LIFE CYCLE ASSET MANAGEMENT 6.22 Total Maintenance and Renewal Expenditure Forecast Figures 137 and 138, shows the split of expenditure by category for maintenance driven tasks for the ten year planning period. A more detailed breakdown of the asset replacement and renewal capital expenditure forecast is provided in Section Maintenance Driven Expenditure Distribution FINANCIAL YEAR ENDING EXPENDITURE TYPE Asset Inspections 1,100,000 1,100,000 1,100,000 1,100,000 1,100,000 1,100,000 1,100,000 1,100,000 1,100,000 1,100,000 Vegetation Management 2,000,000 2,000,000 1,500,000 1,500,000 1,500,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 Maintenance 720, ,000 1,020,000 1,183,500 1,102,500 1,282,500 1,410,000 1,520,000 1,700,000 1,700,000 Faults 1,200,000 1,200,000 1,200,000 1,200,000 1,200,000 1,200,000 1,200,000 1,200,000 1,200,000 1,200,000 Subtotal - Distribution 5,020,000 5,120,000 4,820,000 4,983,500 4,902,500 4,582,500 4,710,500 4,820,500 5,000,000 5,000,000 Transmission Asset Inspections 280, , , , , , , , , ,000 Vegetation Management 180, , , , , , , , , ,000 Maintenance 190, , , , , , , , , ,000 Faults 225, , , , , , , , , ,000 Subtotal - Transmission 875, , , ,000 1,025,000 1,065,000 1,105,000 1,145,000 1,175,000 1,200,000 TOTAL 5,895,000 6,025,000 5,765,000 5,968,500 5,927,500 5,647,500 5,815,500 5,965,500 6,175,000 6,200,000 Figure 137: Maintenance Driven Expenditure by Category 199

202 LIFE CYCLE ASSET MANAGEMENT Maintenance Driven Capital Expenditure Forecast FINANCIAL YEAR ENDING EXPENDITURE TYPE Unplanned Asset Replacement Capital Expenditure (contingency provision) Fault Initiated 440, , , , , , , , , ,000 Asset Inspection Initiated 900, ,000 1,200,000 1,100,000 1,000,000 1,100,000 1,000,000 1,000,000 1,100,000 1,200,000 Planned Asset Replacement Capital Expenditure (Subtransmission and Distribution Network) 1 High voltage conductor 250,000 High voltage pole 370, ,000 1,200,000 1,125, ,000 1,120,000 2,250,000 1,200,000 High voltage power quality and measurement 390,000 High voltage switch 180, , , , , , , ,000 High voltage transformer 108, , ,000 Low voltage distribution pillars 710,000 1,134, ,000 1,628,000 Protection 500, , , , , , ,000 Sub-transmission pole 360, , , , , ,000 TOTAL 3,000,000 3,000,000 3,100,000 3,400,000 3,500,000 3,800,000 3,800,000 4,400,000 4,500,000 5,468,000 Note 1: Asset replacement capital expenditure on transmission assets is classified as network development transmission and shown in Figure 130. Figure 138: Breakdown of Asset Replacement and Renewal Capital Expenditure 200

203 RISK MANAGEMENT Section 8 Risk Management 7.1 Risk Management Policy Risk Management Committee Risk Management Framework Risk analysis outcome Risk Mitigation New Risks Ongoing Risks Health and Safety Policy Transmission Risks Network Critical Spares Emergency Response Plan Lifelines Group Load Shedding Contingency Plans Mobile Substation Risk Register

204 RISK MANAGEMENT 7 Risk Management 7.1 Risk Management Policy Governance of Top Energy is the responsibility of the Board of Directors. The executive management team is responsible and accountable to the Board of Directors for the representation, direction and business success of Top Energy. This delegation of responsibility requires a formal management process, which includes the flow of information to and from the Chief Executive and the Board. All aspects of Top Energy s activities need to be included in this process, including exposure to risk which is a critical aspect in the effective discharge of management responsibilities. The Board is accountable for risk and has an Audit and Risk Committee assigned to monitor relevant issues in depth, but delegates policy execution to the Executive Management Team. Top Energy s approach to risk management starts at the senior management level with its Risk Management Framework. This framework delegates responsibilities for risk management to different functional areas (and individuals) of the business through the use of a Risk Register. Top Energy s Risk Management Framework fulfils the need for an efficient, effective and demonstrable risk management process, which is commensurate with the size of the business. The framework is generally consistent with established principles of risk management and the associated standards (AS/NZS 4360 Risk Management (2004) and HB Risk Management Guidelines (2004)) and builds on these. The framework is authorised by the Board. Where changes are being considered, reference is made to the Institute of Asset Management's specification PAS 55 and the new AS/NZS ISO 31000:2009 International Standard on risk management. In order to ensure that risk management is recognised and treated as a core competency, Top Energy has established a Risk Committee and implemented a cost-effective and coordinated framework for the management of risk. This framework ensures that a formal and consistent process of risk identification, assessment, acceptance and treatment is carried out company wide. Particular emphasis is placed on exposure to business and safety risks that may exist in the short to medium term. In managing the areas of significant risk, Top Energy s risk management framework provides for: the identification of Top Energy s major risk areas incorporating all relevant programmes, processes, projects, activities and assets, a standard framework and risk register for the identification, assessment, acceptance and/or mitigation of risks across all major risk areas, regular reporting of the risk register including reporting of the status of risk profiles, to alert management to any critical changes to Top Energy s overall risk profile, annual reappraisal of the risk register and associated processes by the Executive Management Team with findings reported to Top Energy Board of Directors, and annual reporting to Top Energy s Board of Directors on the levels of risk and the associated management of that risk. Top Energy s risk management framework focuses on the assessment of credible risks. That is, for example, risks comprising of failure due to normal asset ageing processes, overloading, material deterioration, human error, poor workmanship, lightning, fire, earthquake and flood, all within the past experience of Top Energy and other similar electricity companies. Risk events that could be deemed fanciful are not included in contingency plans (e.g. example, aircraft crashing into substations, where these substations are not near airfields or on recognised approach paths to airports). 202

205 7.1.1 Risk Management Committee Risk management is an on-going cyclical process that is managed by Top Energy s risk committee. The risk committee comprises of key individuals from various sectors of Top Energy s business. The following key personnel form this risk committee: Chief Executive Officer General Manager Network General Manager Contracting Services Contracting Services Area Managers Maintenance Manager Operations Manager Information and Communications Technology Manager Projects Engineer - SCADA & Substations Planning Engineer From the above, one person is nominated to manage this committee, organise bi monthly meetings and be responsible for updating the Risk Register. The risk committee is responsible for reviewing and maintaining the risk register. The review includes checks to ensure that: all existing risks are valid, new risks are identified, all risks are appropriately treated/mitigated, existing risk mitigation plans are actioned, and the company s risk management process is being followed. On an annual basis, the risk register is presented to the executive management team. A summary report that outlines Top Energy s risks and any significant changes from the previous register is submitted to Board of Directors for approval at the same time. The Figure below outlines the cyclical review and reporting activities associated with Top Energy s risk management process. RISK MANAGEMENT ACTIVITY RESPONSIBILITY FREQUENCY Update risk register All staff As required Review risks contained within risk register Risk committee Two monthly Risk register/mitigation plan to the Board Executive management Annually Approve risk register and mitigation plans Board Annually Figure 139: Risk management review and reporting cycle 203

206 RISK MANAGEMENT Risk Management Framework Top Energy employs a quantitative approach to risk management that evaluates both risk likelihood and risk consequence. Where event outcomes can be quantified with a probability, this is used in the risk analysis. Risk events of high consequence are more often characterised by uncertainty or surprise than classical probability, which relies on a past history of occurrence. Where past history is not a useful guide to future events, a systematic and rigorous process is needed to firstly discover the risk possibilities. In 2009, the Top Energy executive team engaged a risk management consulting company to facilitate a high level review of the risks faced by the company and the ways those risks are being managed. This review has led to an update of the risk and consequence categories applied to risks for the purpose of analysis. Figure 140 Top Energy risk management process The risk process adopted, which is consistent with AS/ NZS 4360:2004, incorporates the steps shown in Figure 140. The process includes the following main elements: Risk context: Defining the strategic, organisational and physical environment under which the risk management is carried out. Establishing the context involves identifying, planning and mapping out the framework of the whole risk management process. Top Energy s risks are classified in the following areas (domains) and typical sub-areas: GENERAL MANAGEMENT Public/Employees Environmental Regulatory Compliance Asset Management Business Model/Change Management CONSEQUENCE ARISING FROM POOR MANAGEMENT PRACTICES Harm to public Harm to staff Damage to the environment Sustainability Regulatory Compliance General Health & Safety Industry Specific Environmental Loss, Damage, destruction Denial of access Inability to meet customer requirements Inability to meet growth requirements Market Competitive forces 204

207 RISK MANAGEMENT GENERAL MANAGEMENT Financial Products/Services Technology CONSEQUENCE ARISING FROM POOR MANAGEMENT PRACTICES Changed Stakeholder Expectations Poorly managed change processes Revenue loss or constraints Increased Expense flows Liability arising from Product or service delivery High reliance on specific technologies Impact relating to the failure of technology Impact of significant technological changes Figure 141: Risk process main elements Risk identification: Listing all the risks relevant to the risk context. After establishing the context, the next step in the process of managing risks is to identify potential risks. Within Top Energy, anyone and everyone is encouraged to describe and communicate risks before they become problems and adversely affect the company in any way. There are also formal processes based around focus groups that actively identify new and review known risks. Identified risks are considered by the Risk Committee, in particular by the key individual associated with the risk domain. Once approved, it forms part of the risk register and is then managed and or mitigated. Significantly, for an infrastructural asset manager, the risks considered must not be limited to current risks but must also include those risks that may arise over the predicted life of the asset. This long-term view strongly influences the capital and maintenance planning for the network. Risk analysis and evaluation: Estimating the likelihood of the identified risks occurring, the extent of loss and the cost implications and comparing the levels of risks against the preestablished criteria. This enables the decisions to be made. Risks are analysed and evaluated in terms of consequence and probability, which in turn delivers an associated risk ranking level of high, medium or low. It is Top Energy s policy to regularly monitor high and medium level risks. Where possible, additional analysis is undertaken to establish sensible consequence and probability levels. For example, in the case of network outages, consumer s costs of non-supply calculations often involve the analysis of historical asset failure rates. Top Energy s risk analysis and evaluation criteria, which are used to assess each risk that is recorded within Top Energy s Risk Register, are included as Appendix C. Risk treatment: Defining the actions to remove, mitigate or prepare for the risk. This involves contingency plans where appropriate Risk analysis outcome The next Figure schedules the top ten risks identified in Top Energy s risk analysis, the existing controls associated with these risks and further risk mitigation actions to be implemented. 205

208 RISK MANAGEMENT Figure 142: Top ten risks identified 206

209 RISK MANAGEMENT 7.2 Risk Mitigation Examples of some of the most important risk treatment/controls Top Energy recognises are described in the following sections New Risks During recent risk reviews, management and the Board have become concerned by the fact that the company has breached its reliability thresholds in recent years. Despite the extenuating circumstances, this increases the risk of regulatory action. A three year vegetation management programme and extensive program of remote controlled switch installation were implemented and, as a result, network reliability has improved over the last two years. However, it is important not to become complacent and on-going expenditure on vegetation management will be significantly higher than preprogramme levels. Also of increasing concern is the medium-term ability for the network to meet the rapidly growing demand. The risk register shows a growing number of network areas that are rapidly approaching capacity constraints. The consequence of each one is of varying significance, but together they form a major business risk that requires addressing. The network development plan described in Section 5 will address this risk On-going Risks Health and Safety Policy The safety of Top Energy s employees, contractors and the general public is regarded as being of the utmost importance in the operation, maintenance and expansion of Top Energy s Network. Top Energy operates under a Health and Safety System that meets the requirements of the various Acts, Regulations, Codes of Practice and Guidelines that govern the electricity industry. Top Energy has committed itself to a reduction in both the frequency and severity of injuries to staff, contractors and the general public. The results of initiatives implemented in both of these areas demonstrate the commitment by staff at all levels to effectively manage Health and Safety. Our Loss Time Injury Frequency Rate (LTIFR) has dropped from an average of 18 per annum to 3 LTIs in the year 2010/11 (with 1 LTI equalling an LTIFR of 3). In recent years, significant improvement has been made to Top Energy s Health & Safety System. Specific changes have been made to the following areas: employer commitment, planning, review and evaluation, hazard identification, assessment and management, information, training and supervision, incident and injury reporting, recording and investigation, employee participation, emergency planning and readiness, and management of contractors and sub-contractors. These recent efforts have seen a major improvement being made in the time frames and process for the reporting and investigation of incidents Employee commitment continues to grow alongside the continued development of Safe Teams, which involve all employees at all levels in the management of Health and Safety, by including employees in regular meetings to discuss and improve Health and Safety in their individual work areas. Top Energy continues to make a significant investment in the training and development of its employees, as they undergo both regulatory and NZQA Unit Standard based training towards appropriate National Certificates for their various roles. Top Energy offers training to up skill existing 207

210 RISK MANAGEMENT employees in the area of Hotstick, Glove and Barrier, Close Proximity Vegetation, Utility Arborist techniques and Control Room Operator roles. This demonstrates commitment to employee development and increases our ability to maintain the Network efficiently. Top Energy believes itself to be an industry leader in the development of its Authorised Holders Certificate (AHC) System, which allows for assessments of staff current competency who work on and around the network. This assessment process ensures the safety of employees as they only work within their agreed competency. As a result of the enhanced focus stemming from the review of policy statement mentioned above, Top Energy is currently reviewing and re-focusing on the development of a refreshed and ubiquitous Health and Safety culture that thrives everywhere from the boardroom to the field. The initial cornerstone of this culture is a revised field auditing process practised by all levels of management, including the Chief Executive. This is expected to further enhance Top Energy's overall performance. Top Energy s current health and safety policy was recognised by the wider electricity industry in2010 when the company was awarded with ACC Tertiary Level accreditation at the first attempt. Further recognition was gained with the award of the Electricity Engineers Association Public Safety Award in 2010 and Workplace Safety Award in Transmission Risks Top Energy s exposure to risk is extended in respect of the power conveyed over the Transpower Network. Transpower faces similar, if not identical, risks to Top Energy. While Top Energy is not exposed to the cost of material damage to Transpower assets, it is exposed firstly to loss of revenue should Transpower be unable to convey rated demand to the grid exit points, and secondly, by way of lost consumer confidence in electricity as a reliable energy source. To mitigate these risks as reasonably practical, Top Energy has agreed with Transpower to transfer the 110kV transmission assets north of Kaikohe to Top Energy ownership. Top Energy understands that Transpower has also undertaken its own assessment of risk to the transmission grid as a whole and supports efforts and projects that reduce or mitigate these transmission risks. There is on-going consultation with Transpower on the matters that directly and indirectly affect Top Energy Network Critical Spares Top Energy maintains an inventory of critical spares for use in the event of network equipment failure for which there would be long delivery lead times. Top Energy s electrical network is mainly of overhead construction. In most cases, the equipment is relatively modular and can be relatively easily replaced using Top Energy s inventory of equipment held to maintain and expand the electrical network. However, Top Energy maintains a regularly reviewed level of specialised spares and has joined a cooperative group of other infrastructural organisations to provide mutual risk mitigation in this area Emergency Response Plan Top Energy has completed its Disaster Readiness and Emergency Preparedness Plan. Top Energy s Emergency Preparedness Plan ensures that Top Energy s electricity network capabilities are sustained as much as practical through emergency circumstances and events, by the adoption of effective network management and associated practices. Achieving this will ensure that Top Energy meets its obligations to the community, including fulfilling civil defence emergency management requirements, whilst enhancing stakeholder and public confidence. The objectives of this plan and associated arrangements are: To provide general guidelines to be combined with sound judgment, initiative, and common sense in order to address any potential emergency situation, whether or 208

211 RISK MANAGEMENT not that particular set of circumstances has been previously considered. To provide an outline of the roles, duties and obligations of Top Energy and other personnel in preparing for and managing an emergency, prioritised on: o o o o o o protection of life (staff and public), safety and health of staff, service providers, customers and the general public, protection of property and network assets, protection of the environment, on-going integrity of the electricity networks, and establishment and maintenance of relationships and communication channels within Top Energy and with third parties. To provide a business continuity programme for the electricity network that will: o o o raise and sustain appropriate individuals preparedness, competence and confidence to appropriate levels, provide Top Energy with the necessary facilities, information and other resources for response and recovery management, and develop adequate relationships and approaches to ensure sustained plan implementation and evolution. To provide guidance to Top Energy staff for responding to, and recovering from, electricity network emergencies. To assist Top Energy to comply with statutory requirements and accepted industry standards with respect to management and operation of the electricity networks during an emergency. This Plan addresses the management of emergencies related to: Top Energy s own electricity network management facilities and capabilities for its network, Transpower s supply to Top Energy and the coordination of responses and communications. Top Energy s major customers and the coordination of responses and communications. This Plan addresses major emergencies to electricity supply addressing the following four Rs : Reduction (mitigation) of potential and actual threats/impacts arising from a diversity of natural and man-made hazards/risks that surround Top Energy and its assets. This does not extend to the management of network asset related risks separately addressed during Network Planning (Refer Risk Register ). Readiness (preparedness) to anticipate and prepare for potential and actual residual risks/threats beyond those alleviated by other means. Response to a potential and actual emergency in order to stabilise the situation from further danger, damage and unnecessary outages. Recovery following Response, in order to restore full normal services and functions. This comprehensive document covers emergency event classification, emergency response team roles and responsibilities, communications and reporting processes, emergency response prioritisation, detailed emergency response actions and business continuity programme maintenance procedures. The Table of Contents of the document is included as Appendix D. 209

212 7.2.4 Lifelines Group The Civil Defence Emergency Management Act 2002 requires organisations managing lifelines to work together with the Civil Defence Emergency Management group in their region. Lifelines are the essential infrastructure and services that support our community (e.g. utility services such as water, wastewater and stormwater, electricity, gas, telecommunications and transportation networks including road, rail, airports and ports). Top Energy is an active member of the Northland Lifelines Group co-ordinated by the Northland Regional Council. The Group aims to co-ordinate efforts to reduce the vulnerability of Northland s lifelines to hazard events and to make sure they can recover as quickly as possible after a disaster. The role of the group is to: encourage and support the work of all authorities and organisations, including local authorities and network operators, in identifying hazards and mitigating the effects of hazards on lifelines, facilitate communication between all authorities and organisations, including local authorities and network operators, involved in mitigating the effects of hazards on lifelines, in order to increase awareness and understanding of interdependencies between organisations, create and maintain awareness of the importance of lifelines and of reducing the vulnerability of lifelines to the various communities within the region., and promote on-going research and technology transfer aimed at protecting and preserving the lifelines of the region. RISK MANAGEMENT As part of the Lifelines Group coordination activities, Top Energy has voluntarily committed to work with the Northland Civil Defence Emergency Management Group to provide use of the ripple control network for the activation of audible alarm sirens or tones. A procedure has been adopted, the purpose of which is to ensure that Top Energy Ltd meets its commitment to stakeholders to operate our injection equipment and deliver support to the MEERKAT community alerting system. This procedure sets out the requirements for, the acknowledgement of activation requests, the activation of alarms, the process for notifications and the logging of events and activations, and the protocols for testing and reporting of system failures Load Shedding Top Energy maintains a load shedding system to meet its regulatory requirements designed to ensure, at all times, that an automatic under-frequency load shedding system is installed for each grid exit point to which its local network is connected. The system enables at all times the automatic disconnection of two blocks of demand (each block being a minimum of 16% of the total pre-event demand at that grid exit point), when the power frequency falls below specified minimum requirements. Top Energy also maintains an up to date process for the manual disconnection of demand for points of connection in accordance with its regulatory requirements. A feeder shedding schedule is maintained which specifies the shedding priority (manual and automatic) by under frequency zone and substation for the Top Energy 11kV network and the Transpower points of supply. This information is provided on an annual basis to Transpower and the electricity Commission for AUFLs (Under Frequency Load Shedding) requirements. 210

213 7.2.6 Contingency Plans Top Energy has standardized switching instructions that are managed and updated on a regular basis by Top Energy s central control room staff. These switching instructions outline the methods for rearranging the electrical network to supply consumers during network contingencies (equipment outages). Top Energy s existing control room can with some constraints be moved to the Ngawha Power Station or one of Top Energy s regional depots in the event that the main control centre is no longer operational. All critical network equipment can, if necessary, be operated manually Mobile Substation Many of Top Energy's risk scenarios involve customer non-supply through equipment failure in zone substations. In 2002, Top Energy mitigated this risk by purchasing a mobile substation and modifying at risk substations to allow the unit to be installed quickly following formalised procedures. This unit is also used to facilitate maintenance on zone substations and therefore reduce planned consumer outages Risk Register Top Energy s risk register, as developed by the risk committee, is held in a spread sheet. This risk register provides the platform for systematic risk identification and analysis as identified in the above risk management process. From this risk register, additional actions/mitigation-strategies/controls are identified and responsibilities assigned. In some cases significant additional capital expenditure is proposed to remove/mitigate risks. Where this is the case, the planning is passed to the Asset Management Planning process as appropriate. The risks continue to be monitored through the Risk Register. The register enables Top Energy s risk committee to continually monitor the state of the Company s risks and also provides a process for assessing risk. Some risks are on-going and require the Risk Committee to review the state of the mitigation-strategies/controls on an on-going basis. RISK MANAGEMENT 211

214 EXPENDITURE FORECAST Section 8 Evaluation of Performance 8.1 Introduction Review of Performance against Targets Network Reliability Performance Reliability by Feeder Financial Performance Asset Management Improvement Programme

215 EXPENDITURE FORECAST 8 Evaluation of Performance 8.1 Introduction This section presents a review of Top Energy s performance against the set financial and performance targets for FYE Discussion is centred on the various factors that influenced progress and a comparison is made against internal and external industry benchmarks where appropriate. Detailed discussion of performance measures and targets is included in Section 4 of the plan. 8.2 Review of Performance against Targets Network Reliability Performance Consistent with the requirements of the information disclosure regime, network reliability performance is measured by SAIDI and SAIFI. Overall, Top Energy s SAIDI performance was again improved from FYE 2010, although the company s tough SAIDI target was not met within the year. As a result of Top Energy attributable causes, there were a total of: 308 unplanned 11kV and 33kV faults, and 131 planned outages. RELIABILITY MEASURE FYE 2010 TARGET FYE 2010 ACTUAL FYE 2011 TARGET FYE 2011 ACTUAL FYE 2012 Target YTD 2012 Actual SAIDI (excludes Transpower) SAIFI (excludes Transpower) Number of customers without power for 24 hours All Causes Number of customers without power for more than 3hrs ALL Causes < < <25 14 <7,000 19,976 <7,000 19,789 <7,000 11,604 Figure 143: Network reliability performance (YTD Performance as per end December 2011) The most significant causes of Top Energy unplanned interruptions in FYE 2011 were adverse weather, tree contacts, lightning and defective equipment, as indicated in the Figure below. A detailed breakdown of outage statistics is shown in Figure 145. TOP ENERGY CAUSE OF UNPLANNED INTERRUPTION SAIDI % OF TOTAL Adverse Environment Adverse Weather Defective Equipment Foreign Interference Human Element Lightning Tree Contacts Unknown Total Figure 144: Network reliability performance 213

216 EXPENDITURE FORECAST FAULT CLASS FAULT TYPE FAULT COUNT SAIDI SAIFI CAIDI Transpower Faults Loss of Bulk Supply (Unplanned) Subtotal: Top Energy Faults Adverse Environment Adverse Weather Defective Equipment Foreign Interference Human Element Lightning Tree Contact Unknown or Other Subtotal: Top Energy Planned Outages Planned Capital Extension Figure 145: Planned - Planned External Work Planned - Planned Fault Prevention Planned General Planned Maintenance Planned - Planned New Connection Planned Vegetation Control Subtotal: Total: Network reliability statistics Note: TEN Attributable Causes consists of all Top Energy Planned Shutdowns, any faults caused by Defective Equipment, Human Element and Tree Contacts. The pie graphs below shows the contribution of the various interruption causes to total network SAIDI for each of the last two years. 214

217 EXPENDITURE FORECAST Interruption Causes Adverse Environment 0% Adverse Weather 9% Planned Outages 30% Defective Equipment 27% Unknown 9% Tree Contact 13% Lightning 2% Foreign Interference Human Element 9% 1% Planned Planned Outages 5% Unknown 6% Tree Contact 11% SAIDI Adverse Environment 0% Adverse Weather 14% Lightning 1% Human Element 1% Foreign Interference 22% Defective Equipment 40% 215

218 EXPENDITURE FORECAST Unknown 7% Tree Contact 11% Planned Planned Outages 2% SAIFI Adverse Environment 0% Adverse Weather 8% Lightning 1% Human Element 6% Foreign Interference 25% Defective Equipment 40% Figure 146 Interruptions/SAIDI/SAIFI Contribution by Cause Network SAIDI Performance YTD Budget Actual Accumulative SCI Regulatory Threshold SAIDI Figure 147 SAIDI performance trends for FYE

219 EXPENDITURE FORECAST Defective equipment and foreign interference had the most significant impact on network performance with the exception of Planned Outages for FYE It is apparent that overall system performance in terms of gross SAIDI improved from FYE 2010 to FYE 2011 by 5.3%, although the dynamic make-up of the SAIDI contribution has changed somewhat dramatically. Whilst the targeted vegetation programme continues to reduce the impact of tree faults, and proactive distribution maintenance continues to reduce 11kV SAIDI, third-party damage and vehicle versus pole incidents have risen sharply. Overall, 11kV SAIDI has been reduced by an average of 38% across the 11kV system, with the worst performing feeder of FYE 2011 demonstrating half of the SAIDI of the worst performing feeder of FYE This improvement has been offset by the 33kV system performance which, impacted heavily by lightening related equipment failures on the Taipa 33kV line, contributed 88 SAIDI minutes to the annual total. The effect on customers has been significant, with a 31% reduction in the number of customers experiencing greater than five faults and the length of the longest outages being reduced by 12%. Top Energy did not breach its reliability threshold value during FYE 2011, despite a series of major storm events during the course of the year.. The summary of FYE 2011 network performance is listed in the Figure below. FINANCIAL YEAR 2011 FYE SAIDI (MINUTES) FYE SAIFI Regulatory Quality Threshold Major Event Days Nil 0 0 Request for Exemption based on the Guideline 0 0 Year End Top Energy Performance Pre Exemption Post Exemption SAIDI (mins) Below Regulatory Quality Threshold by Figure 148: Top Energy Network Performance Summary of Financial Year 2011 In terms of year to date FYE 2012, the reliability of supply has continued to show incremental improvement over FYE 2011 and it is hoped that the ambitious targets set in the 2011 AMP (which are lower than the Commission s threshold levels) will be met. Overall in terms of SAIDI, the network has demonstrated an improvement in performance of 64 SAIDI minutes or 15.3%, when compared with the same period last financial year. Year-to-date, there has been a total of SAIDI minutes, compared with for the corresponding period within When comparing SAIDI by classification, between the corresponding periods of FYE11 and FYE12, we have seen a marginal increase in the number of reported faults within the categories that are subject to storm damage (i.e. adverse weather, lightning and tree contact). A closer examination of the 2011/2012 SAIDI profiles indicates that we have continued to experience a more consistent level of storm activity within each month throughout the year, than with historical records. Defective equipment fault occurrences have also increased during the period, however at a significantly lower rate than the previous financial year. SAIFI 217

220 EXPENDITURE FORECAST Figure 149 Monthly SAIDI performance trends for FYE 2011 and FYE Reliability by Feeder The following graphs rank Top Energy feeders by their SAIDI performance respectively for FYE 2011 and identifies the worst performing feeders for that year. Figure 150 SAIDI performance by 33kV feeder 218

221 EXPENDITURE FORECAST Feeder FYE2011 Total FYE2011 % FYE2010 Total FYE2010 % Kaitaia % % Kaitaia % % Kaikohe % % Kaikohe % % Kaitaia % - - Kaikohe % % Kaikohe % % Kaikohe % - - Total: Figure 151: Top Energy Network Worst Performing 33kV Feeders FYE2011 Taipa 33kV (Kaitaia ) was the worst performing 33kV feeder for FYE 2011, where SAIDI increased as a result of lightning related equipment failure from minutes to minutes, an increase of 141%. Significant work was carried out on this feeder during the Transpower planned outage on 1 st May Work concentrated on replacing critical equipment that had been assessed as reaching end of life. The most improved 33kV feeder was Waipapa #1, with a decrease from SAIDI minutes to 4.74 SAIDI minutes. Figure 152 SAIDI performance by 11kV feeder 219

222 EXPENDITURE FORECAST Feeder FYE2011 Total FYE2011 % FYE2010 Total FYE2010 % Taipa % % Kaikohe % % Kaikohe % % Omanaia % % Okahu Rd % % Waipapa % % Kawakawa % % Kaikohe % % Waipapa % % Okahu Rd % % Waipapa % % Pukenui % % Haruru % % Omanaia % % Kawakawa % % NPL % % Kaikohe % % Kawakawa % % Moerewa % % Waipapa % % Okahu Rd % % Waipapa % % NPL % % Waipapa % % Kaikohe % % Pukenui % % 220

223 EXPENDITURE FORECAST Haruru % % Taipa % % Okahu Rd % % Haruru % % Moerewa % % Haruru % % Kaikohe % % Moerewa % % Okahu Rd % % Okahu Rd % % Taipa % % Total: % % Figure 153: Top Energy Network Worst Performing 11kV Feeders FYE2011 Oruru feeder (Taipa-1206) was the worst performing 11kV feeder for FYE2011, with SAIDI increasing from 5.69 minutes to minutes, an increase of 125%. FYE 2010 worst performing feeder, South Road (Okahu Rd 1105), has improved its SAIDI by 57%. The FYE 2010 second worst performing feeder, Te Kao Feeder (Pukenui-1305,) has improved its SAIDI performance from to 9.88, an improvement of 135%. Top 10 worst feeders are chosen based on the feeder SAIDI performance ranking and with feeder SAIFI performance taken also into consideration. SAIDI performance has a higher priority than SAIFI for the selection. Nevertheless, six of the 10 worst feeders chosen in terms of SAIDI ranking are also the worst 10 feeders in terms of SAIFI ranking, so it is fairly consistent. FEEDER NAME SAIDI (CLASS B+C) MINUTES % OF TOTAL SAIDI SAIFI (CLASS B+C) % OF TOTAL SAIFI Taipa 33kV % % Oruru (1206) % % Pukenui 33kV % % Awarua (0108) % % Rangiahua (0105) % % Opononi (0506) % % Kawakawa #1 33kV % % South Rd (1105) % % 221

224 EXPENDITURE FORECAST FEEDER NAME SAIDI (CLASS B+C) MINUTES % OF TOTAL SAIDI SAIFI (CLASS B+C) % OF TOTAL SAIFI Whangaroa (0407) % % Russell (0210) % % Figure 154: Top ten worst ranking feeders These feeders are all subject to the expectation of significant improvement over the planning period as a result of the capital investment identified within this AMP. In particular: Taipa 33kV will be substantially improved by the installation of the Taipa emergency diesel generators during FYE2012, Russell will be substantially improved by the proposed installation of the new Russell sub-sea cables or back-up generation together with the installation of a Ground Fault Neutraliser unit, Whangaroa feeder will benefit from the installation of the new Kaeo substation and the improvements to the 33kV network, The South Road, Rangiahua, Oruru, Russell and Purerua feeders have been heavily targeted by the specific reliability projects and have had reclosers and sectionalisers installed to reduce the impact of faults since YE2009, together with the installation of a Ground Fault Neutraliser unit, Te Kao, Opononi, Herekino and Oxford St feeders will all benefit from 11kV upgrades and the 33kV security of supply work planned, and Top Energy will continue with its extensive lines surveys and increased vegetation cutting program on the above feeders. Industry comparison Top Energy has undertaken a benchmarking analysis of System Reliability and Performance indicators from within an appropriate peer group of rural and extensive rural NZ Electricity Lines Businesses (ELBs). The following criteria have been applied using the data from ELBs FY2011 Information Disclosures: larger than 15,000 customer base (i.e. eliminates Small Networks), less than 10 customers per km (i.e. eliminates Urban/Rural and Dense Urban Networks), and underground cable contributes less than 10% of the total system length (High Voltage and Extra High Voltage only, excluding Low Voltage circuits). ELBs chosen for the peer group are the following: Alpine Energy Eastland Network Electricity Ashburton Horizon Energy Distribution MainPower New Zealand Marlborough Lines Northpower The Lines Company The Power Company The next three figures show that TEN s system reliability index (i.e. SAIDI, SAIFI) are in the upper quartile as compared to both the peer group and the industry (note that Class B and C interruptions are considered, with Class A Transpower outages excluded). 222

225 EXPENDITURE FORECAST SAIDI Figure 155 SAIDI for Class B and C Interruptions (FYE 2011) SAIFI Figure 156 SAIFI for Class B and C Interruptions (FYE 2011) The relatively poor level of reliability experienced by Top Energy s customers has reinforced Top Energy s intention to spend significantly on projects that will improve reliability Financial Performance EXPENDITURE CATEGORY AMP BUDGET 2010/11 ACTUAL SPEND 2010/11 Capital $15,454,500 $13,863,000 Maintenance $6,372,000 $5,979,000 Figure 157: expenditure budget compared to actual A detailed review of financial performance for FYE 2011 is discussed in section 9.2 of this plan. 223

226 EXPENDITURE FORECAST The Figure below schedules progress made in implementing projects identified in the 2010 Top Energy AMP. REVIEW OF 2010 ASSET MANAGEMENT PLAN Section Project ID Description Start Date Actual Performance TBC 33kV Waipapa #1 Stage 1 Refurbishment kV - New 110kV line to Waipapa #2 line easements from KOE - WPA kV - New 110kV line to Waipapa #2 resource consents from KOE - WPA 2011 Commenced and ongoing 2010 On-going 2010 On-going kV KER- New substation easements 2010 Completed kV KER- New substation land 2010 Completed 7105 Kawakawa - New 33kV Feeder Link 2011 Completed TBC Ngawha Geothermal 33kV 2nd Line 2011 Completed kV - New 110kV line Kaikohe to Wiroa, Stage Completed TBC 110KV Wiroa Substation Land Purchase and Consent 2011 On-going 7924 Okahu Road Ground Fault Neutraliser Installation 2011 Commenced and completed end SUB - NPL - Line protection for new feeder, Pukenui tap off using 33 NOVA and SEL 351R 2011 Completed TBC Ground Fault Neutraliser Installation Kaikohe 2011 Deferred 7956 Ground Fault Neutraliser Installation Kawakawa 2011 Commenced and ongoing 7266 SUB- WPA New feeder breaker for Waipapa Business centre 6014 SUB - WPA - 4x 750kVAr switched capacitor banks 6895 SUB - WPA 33kV Busbar and protection upgrade 7032 SUB - OMA - Feeder protection upgrade, SEL 351R x 2, SEL 2032, GPS clock SUB - OMA - Sub tap in before boosters for alternate feed from Taheke feeder (Kaikohe 2011 Completed 2011 Completed 2011 Completed 2011 Completed 2011 Completed 224

227 EXPENDITURE FORECAST REVIEW OF 2010 ASSET MANAGEMENT PLAN Section Project ID Description Start Date Actual Performance substation) SUB - OMA - Transformer T1 Protection upgrade, SEL 387E, New NCT 1A, Existing Circuit Breakers ok SWER - LINE - Te Haupua T01324 converts to 3w - Te Kao Feeder DIST - Kawakawa - upgrade all 50 mm Cu leaving substation to Bee conductor. 2 kms, 9001 DIST - New Feeder for Waipapa Business Centre- 11kV 300 mm2 Al Cable 8037 DIST- Purerua feeder- 200 Amp Voltage regulators at 5.11 Km 8039 DIST- Riverview feeder- 200 Amp Voltage regulators at 8.0 Km 2011 Completed 2011 Completed 2011 Completed 2011 Deferred due to reduced development on site 2011 Completed 2011 Completed Figure 158: TBC Mobile generator Purchase 2011 Deferred pending purchase of Taipa Fixed Generation option Progress on implementing major projects identified in the 2011 AM plan The above Figure indicates a reasonable attainment of major project targets. With improved data streams becoming available to the Asset Management Team, it is not surprising that a number of projects have been reprioritised and new projects have been identified. TEN plans to continue to reduce the risk of disruptions and to directly improve the alignment between budget and expenditure in the future. 8.3 Asset Management Improvement Programme The strategy adopted by TEN can be summarised as one of seeking continuous improvement across the range of knowledge building and decision making that it is involved with. Top Energy proposes to continue to build on its present knowledge base to refine the options it will pursue to address the multiple and sometimes conflicting solutions available to provide the desired level of service. Top Energy has undertaken a comprehensive review of current asset management practice using the criteria defined in the UK Publicly Available Specification PAS 55 to: provide an understanding of Top Energy s current position with regard to alignment with PAS55, and identify areas where changes to asset management processes would yield improvements in financial performance, asset performance and risk management. 225

228 EXPENDITURE FORECAST PAS-55 is the Publicly Available Specification for the optimized management of physical assets and infrastructure. Development of PAS-55 was sponsored by the UK Institute of Asset Management in response to a need identified by the UK regulator and asset owners to define asset management in the context of physical infrastructure by setting out the key attributes of effective asset management systems. PAS-55 consists of 21 key requirements, which together provide a framework defining current best practice for the whole of life management of physical assets. The 21 key elements shown diagrammatically below in the figure work together to provide a rigorous process based on the plando-check-act cycle. The requirements link strategic business objectives to detailed operational plans ensuring that operating and capital investment is targeted at realising asset performance and risk profiles that meet stakeholder expectations and business objectives. G eneral Requirem ents M anagem ent R eview & Continual Im provem ent AM Policy M anagem ent R eview 4.6 P olicy & S trategy 4.2 AM Strategy A udit Corrective Actions P erform ance M easurem ent & M onitoring R ecords & R ecords M anagem ent D ocum ent C ontrol C hecking & C orrective Action 4.5 E m ergency P reparedness A sset M anagem ent S ystem Im plem entation & O peration 4.4 O perational C ontrol AM Info, R isk Assessm ent & P lanning 4.3 Com m unication AM Inform ation R isk M anagem ent Legal & Regulatory AM O bjectives A M P erform ance & C ondition AM Plans D ocum entation Training S tructure, A uthority, R esponsibility Figure 159 PAS-55 Asset Management System Elements PAS-55 is now recognised as an internationally auditable specification. As such organisations may seek to obtain independent external certification verifying compliance with the documented requirements. Such external certification is becoming recognised by asset owners and regulators internationally as a useful means to demonstrate good governance, due diligence in the management of asset related risk and optimized asset management decision making. Top Energy is committed to a process of continual improvement within its operational and asset management processes. Top Energy has conducted a medium level gap analysis of its asset management processes against the requirements of PAS-55 with a view to future alignment with or certification against the document. 226

229 EXPENDITURE FORECAST Figure 160 Graphical representation of the 2008 and 2009 Top Energy PAS-55 review results In 2008, Top Energy identified that it was demonstrably weak in several key areas of asset management process control. With the exceptions of Asset Management Plans and Emergency Preparedness, TEN were below the general norm for a New Zealand electricity distribution lines business in most of the areas examined. Key areas identified in which improvement is paramount were: development of a PAS-55 style AM Policy framework, clarification of AM objectives, targets and plans, improvements in the organisational risk management methodology, development of a policy, procedure, standards framework, improvements in Asset Performance, Condition Management and Asset Failure Management, development and implementation of a Training/Competence management strategy, revision and development of a Stakeholder Consultation regime, improvements in Documentation and Records Management, improvements in key aspects of Operational Control, and development of an Audit and Management Review strategy and process. Significant work has been undertaken in these areas to meet the base line requirements of PAS-55. The Asset Management improvement plan adopted is detailed in the following Figures. Significant progress has already been achieved in several items through the implementation of the following strategies: Development of a PAS-55 style AM Policy framework An asset management policy has been developed at divisional level which has been linked to the Top Energy corporate goals and strategies as laid down in the Statement of Corporate Intent. Clarification of AM objectives, targets and plans Clear asset management objectives and targets have been determined which are linked to the Top Energy corporate goals and strategies as laid down in the Statement of Corporate Intent. 227

230 EXPENDITURE FORECAST Improvements in the organisational risk management methodology A corporate risk review was undertaken during 2009 by the Top Energy executive team. The results of this review have been applied in the risk review process within the individual divisions of the company, including TEN. Development of a Policy, Procedure, Standards framework - Although a significant number of policies, procedures and standards have been produced during the course of Operational, Maintenance and Design standards remain one of the key areas for focused improvement within FYE To assist this development, Top Energy has purchased a full set of network standards from Powerco and is recruiting a dedicated manager to manage the development and implementation of Top Energy specific standards in a much shortened timeframe than would usually be possible. Improvements in Asset Performance, Condition Management and Asset Failure Management - A comprehensive condition-based maintenance inspection and management programme has been implemented. An Asset Failure investigation and Management process has been implemented. Development and implementation of a Training/Competence management strategy A comprehensive Authorisation Holders Certificate (AHC) training and competency management system was implemented during Revision and development of a Stakeholder Consultation regime Customer consultation methodology and strategy has been significantly developed during 2009, with the implementation of a successful customer consultation survey during the period. Improvements in Documentation and Records Management Data management and asset records accuracy has been significantly improved during the year with current data accuracy levels in excess of 99.5%. Sharepoint has been adopted as the main document management system. Improvements in key aspects of Operational Control Outage Management processes and protocols have been reviewed during the period, together with the implementation of key emergency management systems and processes (i.e. On-demand and Meerkat) Development of an Audit and Management Review strategy and process A site safety field audit programme was initiated by the Chief Executive and is driven by the operational managers within the business. Whilst a more rounded and mature asset management culture has been established within the company, there is still significant work to undertake to achieve full PAS55 compliance. Top Energy has embarked on formal certification in order to demonstrate continual improvement and comparability against international best practice as part of our annual disclosures. Top Energy has engaged AMCL, an external consultancy company from the UK to assist with the project. Following an initial gap analysis review early in 2012, a detailed action plan will be developed with the aim of the company achieving compliance under the standard by August Top Energy believes that we are the only New Zealand lines company that are pro-actively seeking full PAS certification at this time. There are very few audit bodies that are certified by the UK Institute of Asset Management to carry out PAS55 certification audits. As the popularity of PAS55 continues to grow, their services will undoubtedly become more in demand. Certification to PAS55 should give our stakeholders the confidence that the asset management processes within Top Energy are of an international best-practice standard and are continually being monitored and improved. 228

231 EXPENDITURE FORECAST Section 9 Expenditure Forecast year forecast of capital and operational expenditure Reconciliation of actual expenditure against expenditure for Yr Significant assumptions

232 2011 (Budget) 2011 (Actual) 2012 (Budget) 2013 (Forecast) 2014 (Forecast) 2015 (Forecast) 2016 (Forecast) 2017 (Forecast) 2018 (Forecast) 2019 (Forecast) 2020 (Forecast) 2021 (Forecast) 2022 (Forecast) EXPENDITURE FORECAST 9 Actual, Budget and Forecast Expenditure year forecast of capital and operational expenditure Figure 161 shows the graphical 10 year financial forecast for CAPEX and OPEX. The forecast is developed from the asset information, strategies and prioritisation processes described in Sections 5 and 6 of this plan. The forecasts are compared to the actual expenditure for FYE 2011 and budgeted expenditure in FYE As can be seen from the graph, there is a significant step change in investment in FYE 2013, due mainly to the transfer of Transpower transmission assets. However, even without this transfer, there would still have been a step increase from FYE 2012 in FYE 2013 and FYE 2014, due to the completion of the 110kV line to Wiroa, the establishment of the 33kV Wiroa switchyard and the construction of the Kerikeri zone substation. 40,000,000 35,000,000 30,000,000 25,000,000 20,000,000 15,000,000 10,000,000 5,000,000 - Fault and Emergency Maintenance Refurbishment and Renewal Maintenance Routine and Preventative Maintenance Capital Expenditure: Transmission Capital Expenditure: Asset Relocations Capital Expenditure: Reliability, Safety and Environment Capital Expenditure: Asset Replacement and Renewal Capital Expenditure: System Growth Figure 161 Financial Expenditure Summary The Figures overleaf detail the breakdown of forecast expenditure viewed from a regulatory cost category comparison. The Figure also compare the forecast expenditure for the planning period with the actual expenditure in FYE 2011 and the budget expenditure for FYE

233 EXPENDITURE FORECAST FOR YEAR ENDED 2011 (Budget) 2011 (Actual) 2012 (Budget) 2013 (Forecast) 2014 (Forecast) 2015 (Forecast) 2016 (Forecast) 2017 (Forecast) 2018 (Forecast) 2019 (Forecast) 2020 (Forecast) 2021 (Forecast) 2022 (Forecast) Capital Expenditure: Customer Connection Capital Expenditure: System Growth Capital Expenditure: Asset Replacement and Renewal Capital Expenditure: Reliability, Safety and Environment Capital Expenditure: Asset Relocations Capital Expenditure: Transmission Subtotal - Capital Expenditure on Asset Management 800,000 1,006,000 1,000,000 1,045,000 1,045,000 1,045,000 1,045,000 1,045,000 1,050,000 1,045,000 1,045,000 1,045,000 1,050,000 7,083,000 6,713,000 6,686,006 11,821,590 6,567,000 3,580,000 6,934,000 6,585,000 5,256,000 7,262,500 7,387,000 3,212,000 3,295,000 4,045,000 5,046,000 4,085,000 3,000,000 3,000,000 3,100,000 3,400,000 3,500,000 3,800,000 3,800,000 4,400,000 4,500,000 5,570,000 3,304, ,000 5,392,500 6,596,500 11,085,000 9,889,500 6,393,000 7,857,000 5,374, ,000 1,080,000 3,929,764 5,500, , , , ,706,000 3,047,076 4,124, , ,181 3,510,000 3,260,878 2,080,000 3,250, ,000 15,454,500 13,863,000 17,338,506 29,169,090 24,744,076 21,739,354 18,447,337 19,969,181 18,990,000 15,958,378 15,992,000 15,936,764 15,915,000 Operational Expenditure: Routine and Preventative Maintenance Operational Expenditure: Refurbishment and Renewal Maintenance Operational Expenditure: Fault and Emergency Maintenance Subtotal Operational Expenditure on Asset Management 4,422,000 3,952,000 4,100,000 3,560,000 3,590,000 3,130,000 3,170,000 3,210,000 2,750,000 2,790,000 2,830,000 2,830,000 2,830,000 1,000, ,000 1,077,500 1,135,000 1,010,000 1,210,000 1,373,500 1,292,500 1,472,500 1,600,000 1,710,000 1,920,000 1,945, ,000 1,298, ,000 1,200,000 1,425,000 1,425,000 1,425,000 1,425,000 1,425,000 1,425,000 1,425,000 1,425,000 1,425,000 6,372,000 5,979,000 6,077,500 5,895,000 6,025,000 5,765,000 5,968,500 5,927,500 5,647,500 5,815,000 5,965,000 6,175,000 6,200,000 Total Direct Expenditure on Distribution Network 21,826,500 19,842,000 23,416,006 35,064,090 30,769,076 27,504,354 24,415,837 25,896,681 24,637,500 21,773,378 21,957,000 22,111,764 22,115,000 Overhead to Underground Conversion Expenditure Figure 162: Comparison of Actual, Budget and Forecast Expenditure FYE 2011 FYE 2022 by Commerce Commission Category 231

234 EXPENDITURE FORECAST 9.2 Reconciliation of actual expenditure against expenditure for FYE 2011 The following Figure shows the financial performance for FYE2011: EXPENDITURE CATEGORY ACTUAL BUDGET VARIANCE Capital Expenditure: Customer Connection 1,006, , % Capital Expenditure: System Growth 6,713,000 7,083, % Capital Expenditure: Asset Replacement and Renewal 5,046,000 4,045, % Capital Expenditure: Reliability, Safety and Environment 946,000 3,304, % Capital Expenditure: Asset Relocations 152, , % Capital Expenditure: Transmission - - Subtotal - Capital Expenditure on Asset Management 13,863,000 15,454, % Operational Expenditure: Routine and Preventative Maintenance 3,952,000 4,422, % Operational Expenditure: Refurbishment and Renewal Maintenance 729,000 1,000, % Operational Expenditure: Fault and Emergency Maintenance 1,298, , % Subtotal - Operational Expenditure on Asset Management 5,979,000 6,372, % Total Direct Expenditure on Distribution Network 19,842,000 21,826, % Figure 163: FYE 2011 expenditure Comparison of Budget and Actual Capital expenditure finished within 10.3% of the AMP budget expenditure for the year, with the majority of projects completed on time. A small number of larger value distribution projects were commenced, but remained incomplete as of the 31 March 2011, although plant and materials had been purchased but not installed. Projects that were rolled into FYE 2012 include the Kawakawa and Okahu Road Ground Fault Neutraliser installations, the commissioning of the Ngawha 33kV line and a section of the Kaikohe to Wiroa 110kV line, due to problems obtaining landowner consents. The committed capital cost of materials for these projects was $1.2m. Projects carried forward from FYE 2010 and that were completed in FYE 2011 included the Waipapa Ground Fault Neutraliser, the Mt Pokaka transformer installation and associated works, the Mt Pokaka double circuit 11kV feeder line and the main Ngawha to Kaikohe 33kV line. The maintenance programme was completed to schedule and within 6.2% of budget. The underspend of $393k was due to a combination of the planned asset inspection programme completed to schedule and ahead of budget, Vegetation Management completed to programme for the year and below budget, both offsetting an over expenditure on Faults due to the storms which impacted in the final quarter of the year. The maintenance strategies aimed at improving network reliability identified in the 2009 AMP and followed through in the 2010 AMP have been successfully continued into FYE These projects, which include the Vegetation Management Strategy, lightning mitigation and the installation of Auto- Reclosers, Line Sectionalisers and Remote Controlled Switches, have enabled the network to be more robust in extreme weather conditions and to be isolated and restored more efficiently. 232

235 EXPENDITURE FORECAST Top Energy is nearing completion of its first complete round of asset inspections. The Asset Management System now has a good base of information about the condition of most asset types. This allows rudimentary analysis on network condition, enabling projection of maintenance and replacement budgets and workloads. It is anticipated that as these systems mature data quality and analysis will improve accordingly. This will increase Top Energy s knowledge and provide focus and direction on maintenance and renewal needs Capital Expenditure Customer Connection Several major connection projects were commenced and completed during the financial period, which was not previously identified within the AMP budget. These included the Mt Pokaka Substation connection and the Ngawha Geothermal Station dedicated 33kV supply. These, together with smaller subdivision developments, resulted in a higher than expected value for customer connection projects for the year Capital Expenditure Asset Replacement and Renewal Asset replacement expenditure exceeded budget during the year, partially due to the advancement of switchgear and pole replacements that were identified as critical during the period. This expenditure of approximately $1m was utilised to offset the reduction in expenditure on reliability, safety and environment projects Capital Expenditure Reliability Safety and Environment Reliability, safety and environment expenditure was reduced by approximately $2m against budget during the year, due to the advancement of switchgear and pole replacements that were identified as critical during the period. This expenditure of approximately $1m was transferred to the Asset Replacement and Renewal budget. The remaining $1m was for earthing and pillar remediation projects, which were deferred due to the storms which impacted on resource availability during the final quarter of the year Capital Expenditure Asset Relocations Asset Relocations did not achieve the forecast budget, due to the lower than expected applications for asset relocations during the period Operational Expenditure Preventative and Routine Maintenance Routine and preventive maintenance was reduced during the third and fourth quarters of FYE2011 by approximately $470k to off-set a reduction in revenue, due to a downturn in domestic consumption identified during the first half of the year. This did not impact on the maintenance and vegetation management schedule, which achieved targets for the year. The remainder of the shortfall was recovered from reductions in overhead expenditure associated with training, consultancy and business travel expenditure Operational Expenditure Refurbishment and Renewal Maintenance Refurbishment and renewal maintenance was reduced during the final quarter of FYE 2011 to offset over-expenditure on system faults, due to three months of tropical storms and cyclones Operational Expenditure Fault and Emergency Maintenance Fault expenditure exceeded budget during the year due to the increased level of storms that were experienced during the final three months of the financial year. These storms, including cyclone Vania and two tropical storms impacted both SAIDI and financial performance from January through to April

236 9.3 Significant assumptions The next Figure records the significant assumptions made in preparing the financial forecasts, the basis for the assumption and the potential impact of the associated uncertainty. EXPENDITURE FORECAST 234

237 EXPENDITURE FORECAST ISSUE ASSUMPTION BASIS FOR THE ASSUMPTION POTENTIAL IMPACT OF UNCERTAINTY GROWTH FUNDING It has been assumed the cost of developing the network for growth and customer connections will be financed by the additional income from the network customers plus contributions from customers for new connections Due to the step change in capacity required on the network, we have approached funding with a combination of increasing bank borrowings, the sale and lease back of buildings, inter group transfer of funds from the investment in Ngawha Generation and finally line revenue increase. This allows TE to keep the year 0 increase to customers as low as possible. Over time our step increase in network investment will drop to a lower level this should assist in stabilising future pricing. In the short term an increase in revenue at Po is required. The principal sources of information for developing this assumption are: If growth as assumed does not go ahead, in theory the expenditure for customer connections and growth as detailed in the long term plan would reduce. However, as 80% of the Top Energy network currently does not meet our security of supply standard, a slowdown in growth will have little or no effect on the investment programme that we have in place. Load growth estimates, and actual consumption over recent years are detailed in the Asset Management Plan. Network models that calculate network capacity and the impacts of growth on the connection chain. The cost of the necessary network development. REGULATORY CONTROL Regulatory controls encourage investment in infrastructure, asset replacement and maintenance of existing assets to provide target service levels and an adequate return on the investment. The assumption aligns with the government s Energy Policy to encourage investment in infrastructure. Uncertainty over the regulatory pricing implications for the coming five year period and uncertainty beyond that period. GXP CAPACITY Transpower GXP capacity, grid support projects and security requirements will be delivered to continue current service levels. The costs of maintaining these service levels are passed directly through to customers. DISTRIBUTED GENERATION That distributed generation connections will continue to be developed and that the regulators resolve rules on complex issues associated with grid exit power factor. It is assumed that industry rules will be formatted in such a way that grid connected and distribution connected generation face a similar matrix of costs. (This is currently not the case). It is also assumed that existing load taking customers will not be penalised in a way that cross subsidises the connection of generation. This assumption is based on government policy statements and the lack of rules to cover some of the complex technical issues associated with connecting distributed generation. It has also been assumed that the regulators will want to make the connection of generation equitable between transmission and distribution networks. The principal sources of information for developing these assumptions If regulators enforce grid exit power factor requirements and costs are passed on to generation, the economics of some existing and new distributed generation sites will become marginal. If the costs are passed onto load taking customers, charges will have to increase. If regulators accept that grid exit power factors with generation connected will be lower, but the same amount of reactive power would have to be supplied into that point with or without the active power injection, then 235

238 EXPENDITURE FORECAST ISSUE ASSUMPTION BASIS FOR THE ASSUMPTION POTENTIAL IMPACT OF UNCERTAINTY are: Government policy statements Electricity Governance Rules Transmission connection charges Various papers produced by officials Network studies showing the effects of distributed generation there would be no additional revenue requirements (status quo). The costs associated with a greater uptake of distributed generation will mean that the customer connection and system growth expenditure will increase to accommodate this. DEMAND SIDE MANAGEMENT AND PEAK CONTROL That the industry will increasingly recognise the importance of demand side management and peak control. A consequence of this will be recognition and support for TEN s demand based charging system by regulators. This assumption is based on the fact that power systems have to be designed for peak capacity. Increased power system efficiency and minimisation of investment comes largely by minimising demand. Power factor is also directly related to power system efficiency and is part of demand side management. Losses and investment are minimised if power factors are close to unity and demands are controlled. Customers reaction to demand side management signals to date has been encouraging. Retailers have yet to introduce energy rates that provide reasonable incentives for customers to manage their demands. If retailers introduce incentives and the industry moves to implement more demand side management schemes, then customers will likely understand the issue better and greater savings will occur. This assumption is based on the information that suggests investors will want to minimise costs for network development, i.e. customer connection and growth development costs. All stakeholders want costs controlled and environmental lobbies want losses minimised. Power factor and changing demand behaviour affects losses. ECONOMIC It has been assumed that economic activity based on primary production and processing will The network studies have assumed continued development of the area. Different rates have been used If economic activity increases, growth related capital expenditure will increase. If economic activity reduces, the 236

239 EXPENDITURE FORECAST ISSUE ASSUMPTION BASIS FOR THE ASSUMPTION POTENTIAL IMPACT OF UNCERTAINTY ACTIVITY continue to develop albeit gradual and at a slow pace. That is, the forward assumptions include allowances for existing dairying land being converted back to dry stock farming and visa versa. It is assumed that when land is converted to dairying, present day technologies will be incorporated into new milking sheds. These tend to be bigger and more automated than older installations. The forward land use assumption does not include large scale development of irrigation. on land of different types based on present usage. For example, it has been assumed flat or rolling land will see greater development than hill country in remote locations. Areas to which people are currently attracted to build new homes and invest in related enterprises have been given greater growth rates than locations that are less popular and more remote. Overall this produces an average growth rate of less than recent times, but reflective of consistent growth has been used as a base. TEN s growth is also influenced by rural based industrial enterprises. Models have assumed that most of these industries will continue with a gradual increase in load as various machines within the plant are renewed. It has also been assumed that, because of TEN s pricing structures, industrial customers will focus on demand side management by way of power factor correction and recognising the demand the various processing within the plant creates. reverse will not take place. This is because TEN has underinvested in the network for a significant period and we are currently catching up to meet our security of supply standards. If economic activity declines to a level that sees a number of the rural processes leave the area, then TEN will have to either reduce renewals or increase revenue from the remaining customers. The principal sources of information for developing these assumptions are: CPI. Land information. New housing areas. Areas that are static or depopulating. Industrial customer feedback and comment. Previous energy and demand growth figures. Primary produce pricing and trends in these. 237

240 EXPENDITURE FORECAST ISSUE ASSUMPTION BASIS FOR THE ASSUMPTION POTENTIAL IMPACT OF UNCERTAINTY Predictions on primary produce long term forecasts. Predictions on the leisure markets. CUSTOMER EXPECTATIONS Establishment of service levels continue to be through consultation with stakeholders and remain a balance between customer needs, pricequality trade-offs and industry best practice. Performance targets driven by customer consultation indications. This is focussed on determining the number of acceptable outages and the acceptable length of each outage. These are then collated to produce an overall target for the network. This is then benchmarked against similar lines companies in terms of overhead line % and customer density to validate the targets. It is expected that customers expectations will increase as the quality of supply improves. This means that in targeting performance improvements we need to be mindful of both current and future expectations. This is why the combination of customer feedback and industry benchmarking is important. RELIABILITY AND QUALITY It has been assumed that customers will want reliability and quality standards equivalent to or better than present to support lifestyle tools such as electronic appliances, computers and media devices. The reliability and quality assumption is based on the understanding that customers want an improvement in reliability and quality. Specifically, this assumption is based on historical levels of reliability we have delivered as well as Customer Consultation. The principal sources of information for developing these assumptions are via: The forward plans include projects totalling about $200,000 p.a. for reliability development (mostly automated switches). If stakeholders do not want a gradual improvement in reliability, then this expenditure could be eliminated. Industry benchmarking which shows our reliability as the worst in the country Customer feedback Complaints There will also be significant improvements in reliability as a result of the security projects. Currently the majority of the customers on the TEN network are served by a single sub transmission line. As more lines are built the risk of loss of supply due to a single line fault will be eliminated for 80% of our customers. Focus groups Customer representatives Other community input. HAZARDS That stakeholders want a network that does not cause an unacceptable level of hazard to the general public, staff, or animals. We do not believe that there are significant hazards present on the network. We have on-going plans to reduce minor network hazards over the planning period. Due to the low level of these hazards it is assumed that there will be no stepped The hazard assumption is based on people not wanting to get shocked or electrocuted. The assumption is that the network was originally designed and built to minimise these hazards. It is recognised that some are inherent in the network e.g. flying a kite into a line or driving a car into a pole. TEN has a focus on renewal programmes, maintenance to ensure that we operate a network with acceptable The present programme eliminates or minimises the worst of these low level hazards by about The annual spend would be reduced in the medium term if the programme were lengthened. In the unlikely event that stakeholders decide not to have a programme with projects that eliminate/minimise hazards, then the forward development expenditure 238

241 EXPENDITURE FORECAST ISSUE ASSUMPTION BASIS FOR THE ASSUMPTION POTENTIAL IMPACT OF UNCERTAINTY inputs to significantly alter this plan. The Asset Management Plan includes specific sites and conceptual design detail. low levels of hazards. This assumption assumes that TEN will not operate in a way that exposes the business to the liabilities associated with not taking all practicable steps to minimise and eliminate hazards. would reduce by approximately $1million p.a. It should be noted that it is unlikely that this would be approved by Top Energy s board of directors. ASSET RENEWALS Projected Asset Replacement and Renewal expenditure levels beyond the first five years of the planning window. The projected Asset Replacement and Renewal programme is based upon the known condition and defect information gathered during annual asset inspections, together with estimated failure rates for assets of a specific age profile. Identification of specific asset issues may cause increased expenditure for certain asset classes within future years (ie the identification of an inherent safety risk with a particular asset forcing rapid replacement or removal from operation). FAULT AND EMERGENCY MANAGEMENT The weather is the biggest factor in fault and emergency maintenance. Storms that involve wind speeds greater than 75km/hr have been shown through post fault analysis to have a significant effect on the TEN network. Post fault analysis following major storm events. PRICING It has been assumed that TEN will continue with its present pricing structures that are designed to be transparent, promote demand side management, encourage distributed generation and reflect asset values/costs. The assumption is based on the regulators and stakeholders continuing to encourage efficient network development and for revenue to reflect cost drivers. Pricing is set as a direct result of the regulators views on an acceptable return on investment. If this Default Price Path does not produce an acceptable return, then the company will consider a Customised Price Path. The present pricing structure promotes demand side management and protects revenue against movements in energy flow triggered by shortages or greater uptakes of micro domestic generation. A change in the structure would increase the risks to revenue in the future. INFLATION 1 It has been assumed that inflation will affect the annual forecast expenditure though the planning period. The rate of inflation for cost increases has been based on recent CPI figures. The assumption is based on published CPI data. Forward estimates are based on an inflation rate of 3%. Higher inflation will mean higher costs in dollar terms. Lower inflation will give the reverse. 1 The inflation referred to is that associated with the renewal and construction of distribution networks, not general inflation Figure 164: Significant assumptions related to the financial forecast 239

242 APPENDICIES Section 10 Appendices 10 A p p e n d ic e s Appendix A Nomenclature Appendix B 2009 Customer Consultation Survey Questions Appendix C Risk Management Framework Risk Management Process Risk Management Context Appendix D - Emergency Response Plan Table of Contents Appendix E Cross References to Requirements of Electricity Information Disclosure Handbook 2004 (as amended 31 October 2008) List of Tables... Error! Bookmark not defined List of Figures

243 APPENDICIES 10 Appendices 10.1 Appendix A Nomenclature GENERAL kv kilo-volt ka kilo-ampere kw kilo-watt MVA MW MVAr ka rms 3-phase GIS GPS CMMS SCADA OH UG GXP 1,000 volts of voltage, typically used in the description of the nominal rating of transmission (110kV), sub transmission (33kV) and distribution (11kV, 22kV and 6.35kV) circuits. 1,000 amperes of current. Fault current is typically measured in ka or its MVA equivalent, according to MVA=sqrt3 x kv x ka. 1,000 watts of real power (e.g. a 2kW oil-filled heater is real power the consumer actually uses, represented on the x axis) as opposed to reactive power, which is the quadrature component. One million volt-amperes (1,000 kilo volt-amperes) of apparent power. Apparent power is the vector equivalent of reactive or quadrature component power and real power. Apparent power is typically larger than either real or quadrature power and is the quantity that the system actually needs to provide, in order to get real power to the consumer. Generators and lines are all rated in terms of MVA, but the consumer typically only uses real power, a lesser quantity. The quadrature difference is used in the equipment and circuits along the way and is necessary for them to work. One million watts (1,000 kilo watts) of real power. The quadrature vector component, that when added to real power, gives apparent power. One of the ratings of equipment is square-root of the mean of the squares. 3-phase or three phase means 3-phase power. In this case there are three conductors, in this country red, yellow and blue. All three phases are out of phase with each other by 120 degrees. INFORMATION TECHNOLOGY RELATED Geographic Information System. A computerised system that spatially represents the assets. Global Positioning System. Handheld GPS devices receive and average locational signals from multiple satellites to give a location. The device includes software called a data dictionary, whereby attributes of the asset being captured are also entered. The data captured with GPS devices is entered onto the GIS system. Computerised Maintenance Management System involving a register of asset type, its condition, interlinked to the GIS and to the financial system. A CMMS is used to implement maintenance strategies in a consistent manner for large volumes of assets. This involves interaction with mobile hand-held information technology devices, scheduling, prioritizing and interaction with the financial system both at estimating/works order stage, for invoicing, general ledger and work in progress reporting. Supervisory Control and Data Acquisition. A system involving communication equipment to monitor and control remote equipment from a central point. It includes remote terminal units (RTUs) to marshal signals at the remote location and communication either via radio, microwave or the telephone system. The central control point receives and sends signals to the remote equipment. Data is logged here and control functions may occur either according to the control room operator s command or automatically. Overhead. Underground. CIRCUIT RELATED Grid Exit point. A Transpower substation where electricity is stepped down from a voltage of 110kV (the transmission voltage used in Top Energy s area) to 33kV and fed to Top Energy s zone substations 241

244 APPENDICIES over a sub transmission system. Sub transmission Zone substation Distribution Distribution substation/ Distribution Transformer LV SWER Transfer capacity ( 3h) Firm capacity (N-1) Switched capacity Note Circuits carrying electricity at 33kV (in Top Energy s case) from the GXP s to Top Energy s zone substations. A Top Energy facility that steps the electricity down from 33kV to 11kV or 22kV for distribution out to the locations near to customers. Both OH and UG circuits at 11kV, 22kV, or 6.35kV that distribute power from zone substations to distribution substations or distribution transformers. A facility involving either a pole mounted transformer or a ground-mounted transformer, whereby electricity is stepped down from distribution voltage (11kV, 22kV or 6.35kV) to low voltage. Low voltage circuits either OH or UG at either 415V 3 phase or 480V/240V single phase that reticulate electricity from distribution substations to customers premises. A lowest cost distribution system called single wire earth return (SWER) used to reticulate electricity to remote areas involving low load densities. The start of the SWER system is a pole mounted isolating transformer where electricity is converted from conventional two or three -wire 11kV distribution to either 11kV SWER or 6.35kV SWER, which are the two SWER types used at Top Energy. The SWER itself involves a single overhead conductor run to conventional distribution substations or distribution transformers near to the customers. The return conducting path to the isolating transformer is through the earth. This avoids the additional cost of two or three overhead distribution conductors. Once the electricity reaches the distribution substation, LV reticulation to homes occurs in the conventional manner. The substation load that can be switched away to adjacent substations within three hours. It is considered that one feeder could be switched within this time. Accordingly, it is the largest of the feeder loads that can be picked up by adjacent substations in an emergency condition. For a two transformer substation, is the minimum of the two transformers plus the transfer capacity (3hr). The transfer capacity is considered a contribution to firmness, because this load can still be supplied within three hours from elsewhere. Firm capacity cannot occur at a substation with only one transformer (e.g. Moerewa, Taipa, Pukenui and Omanaia). The sum of capacities that can be supplied to the zone substation location, including transfer capacity ( 3hr), from elsewhere if that zone substation is out of service. Top Energy sizes its transformers for local load forecast and future envisaged transfer capacity for feeders between a zone substation and its neighbour that a zone substation would have to supply if the neighbouring zone sub failed. Top Energy s approach is to cover one major equipment outage event, not two. So if a zone substation fails, the feeders between it and an adjacent zone substation are picked up by the adjacent zone substation, with all of the transformers at the adjacent zone substation operating concurrently. If Top Energy were to cover the event of both a zone substation failing and one of the transformers at an adjacent zone substation also failing concurrently, then that would require much larger transformers and an approach that Top Energy considers inappropriate for a substantially rural lines business. CONDUCTOR RELATED ACSR HD AAC ABC PVC XLPE PILC PILCSWA Aluminium Conductor Steel Reinforced conductor used for OH lines Hard Drawn All Aluminium Conductor Aerial Bundled Conductor involving an overhead, insulated multi-core cable. Polyvinyl Chloride. An insulation used for low voltage conductors. Cross linked Polyethylene. An insulation type prevalently used for conductors at distribution and sub transmission voltages. Paper Insulated Lead Sheathed Conductor. Copper conductor with insulation of PILC and Steel Wire Armour. An outer light PVC serving is typically used outside of the armour. 242

245 APPENDICIES OTHER EQUIPMENT RELATED ABS Pillar Box or Pillar RMU Recloser Sectionaliser Circuit Breaker (CB) Air Break Switch. These are manually operated or motorised remote control switches. These switches are used to create an open point between two feeders, to achieve more operational flexibility on the lines. A ground mounted LV fuse enclosure, where electricity from LV circuits is connected to the final LV service mains to customers premises. Ring Main Unit. A ground mounted unit with set of three switches, one with fuse arrangement. The fused switch is configured as a Tee-off. The units are earthed. Normally a pole-mounted protection device acting as a small circuit breaker on either a sub transmission or distribution circuit. An automatic circuit recloser is a self-contained device with the necessary circuit intelligence to sense over current, to time and interrupt the over currents and to reclose automatically to re-energize the line. If the fault should be permanent, the recloser will lock open after a pre-set number of operations and isolate the faulted section from the main part of the system. A Sectionaliser is a pole mount protective device that automatically isolates faulted sections of line from a distribution system. Normally applied in conjunction with a backup recloser or breaker, a sectionaliser opens and allows the backup device to reclose onto the remaining unfaulted sections of the line. A circuit breaker is usually employed at the substation level in distribution system over current protection applications. It is a mechanical switching device capable of making, carrying and breaking currents under normal operation and also capable of making, carrying and breaking currents under specified abnormal condition for a specified time. TRANSFORMER RELATED COOLING NOMENCLATURE ONAN ONAF OFAF ODAF Oil Natural, Air Natural (no fans or pumps) Oil Natural, Air Forced (fans but no pumps) Oil Forced, Air Forced (fans and pumps) Oil Directed Flow, Air Forced (fans and typically pumps plus internal vanes that direct oil flow through the core-coil winding assembly) TRANSFORMER CONDITION NOMENCLATURE DP PD Degree of Polymerization. This is a measure of the condition of cellulose-based paper insulation in oil. A new transformer will have a DP value of around 1,000. Through a combination of pyrolysis and hydrolysis, the paper-in-oil insulation gradually degrades to an end life of around DP 150 to DP200. The most accurate way of ascertaining DP is through an actual paper sample cut opportunistically from the core-coil assembly during a major refurbishment, or from a small sample piece of paper insulation, if the manufacturer has provided one in an easy to get at location, typically at the top, inside the transformer tank. Not all manufacturers provide this unless asked, including those that supply Top Energy. Outside of major refurbishment occasions, a less invasive method is to indirectly determine DP through analysing Furan derivatives from an oil sample. Furans are a by-product of the cellulose degradation process. An indication of whether a Furan analysis or further investigation would be required is obtained from Dissolved Gas Analysis (DGA) whereby dissolved gas by-products from pyrolysis and hydrolysis action in an oil sample are analysed using gas spectrometer and other means. Other electrical tests may also be used as required to give an indication to the engineer of what is happening inside the transformer, one of the most revealing ones being partial discharge analysis. A partial discharge is essentially a minor conduction across an insulation medium, not exactly a full discharge, which would be a spark that would involve full insulation failure. A partial discharge by contrast gives an early indication of insulation degradation. Full failure is typically some time away, this could be anywhere from imminent, to months or even years away. The PD techniques enable this to be analysed, failure times predicted and more importantly, the location of degrading insulation to be pin-pointed. In the case of a transformer, before the expensive process of de-tanking. 243

246 APPENDICIES Buccholz Relay A protection device on a transformer situated below the header tank or conservator. Gases generated inside the transformer will gravitate up to this point. If the magnitude of them is sufficient, the relay will operate and trip the transformer, hopefully before a failure involving serious damage can occur. BUSINESS RELATED ODV SAIDI: Optimised Deprival Valuation. An industry-wide standard method of valuing monopoly lines businesses set and administered by the New Zealand Commerce Commission to enable line business performance to be compared consistently and as the basis for regulatory control of maximum return on assets. OUTAGE RATES FIGURES OF MERIT System Average Interruption Duration Index calculated by: I.e. the expected number of minutes a customer will be without power in a year SAIFI: System Average Interruption Frequency Index calculated by: I.e. the expected number of outages per year for any customer CAIDI: Customer Average Interruption Duration Index calculated by: I.e. the average duration of an outage 244

247 APPENDICIES 10.2 Appendix B 2009 Customer Consultation Survey Questions The survey asked the following questions. QUESTION Thinking of yourself as a (domestic, Commercial, Industrial) customer, when was the last time your power went off? How would you rate the reliability of your current power supply? PROMPTS Can t remember, days ago, weeks ago, months ago, years ago Acceptable, more than acceptable, unacceptable, more than unacceptable Over the past few years do you feel that the reliability of your power supply has...? IT MAY SURPRISE YOU/IT WON'T SURPRISE YOU - then that the power supply reliability has decreased over the last three years. Top Energy customers last year experienced an average of 18 hours without electricity and up to 27 outages each. Do you think this is acceptable? Would you like to see an improvement in the reliability of the power supply? (i.e. less power cuts) Got worse, improved, stayed the same Don t know, no, yes Don t know, no, yes When the power cut occurs, how long should the lights be off? Less than 2 hours, 2 to 6 hours, 6 to 10 hours, more than 10 hours How many times per year do you think it is acceptable for your power to go off? Have you ever experienced very short power cuts of less than one minute? Would you say these short interruptions are...? If you had to choose, would you rather have more power cuts which last a shorter time or fewer power cuts lasting a longer time? Customers in the Far North of our area rely on a single line to Kaitaia, this means they go without power one day every year while maintenance work is completed. As there are no alternatives if there was a problem with this line then electricity will stay off until a repair is made, this could be 24 hours or more. These problems can be fixed by installing a second line. The only way to fund this is an increase in price, how much more would you be prepared to pay per month for this line? or would you prefer not to have a second line? Would you expect that a commercial business setting up in a major town in the Far North would have access to electricity sufficient for their needs? If you could tell Top Energy one thing about how they could improve their service, what would it be? Never, less than 3, 3 to 5, 5 to 8, more than 8 Don t know, no, yes No problem, a slight inconvenience, an inconvenience, a major inconvenience Fewer for a longer time, more for a shorter time No line, 6, 12, 18 Don t know, It depends, no, yes Communication, no comment, lower prices, more sustainable power sources, prices down, retail power 245

248 APPENDICES 10.3 Appendix C Risk Management Framework Risk Management Process The adopted WDC risk management process is consistent with Australian/New Zealand standard AS/NZ 4360 (now superseded by AS/NZS ISO 31000:2009), which defines risk assessment and management Risk Management Context The key risk criteria adopted for assessing the consequences of identified risks are: health and safety, financial impact, environmental impact, public image/reputation, business interruption, and regulatory compliance. Risk Analysis: The likelihood and impact definitions used to determine initial risk ratings are defined in Figures D.1 and D.3 respectively. Figure D.2 shows a graphical representation of the resulting matrix of likelihood and impact ratings used to prioritise risks. RARE UNLIKELY POSSIBLE LIKELY ALMOST CERTAIN Event may occur, but only in exceptional circumstances The event could occur at some time The event is not uncommon. Likely to occur despite best efforts. Likely to occur several times. Occur less than once in 20 years Occur once every 10 years Occur once every 5 years Occur once a year Occur more than once per year Figure E.1- Risk probability definitions INSIGNIFICANT MINOR MODERATE MAJOR CATASTROPHIC ALMOST CERTAIN 1 H H E E E LIKELY 2 M H H E E POSSIBLE 3 L M H E E UNLIKELY 4 L L M H E RARE 5 L L M H H 246

249 APPENDICES E H M L Extreme Risk - Should be brought to the attention of Directors and continuously monitored High Risk Requires the attention of the CEO and General Managers Moderate Risk appropriately monitored by middle management Low Risk Monitored at a supervisory level Figure E.2- Risk prioritisation definitions 247

250 APPENDICES CONSEQUENCE HEALTH & SAFETY FINANCIAL IMPACT ENVIRONMENTAL IMPACT PUBLIC IMAGE REPUTATION BUSINESS INTERRUPTION REGULATORY Catastrophic Multiple fatalities Serious long-term health impact on public Financial costs or exposure exceeds $75M (DCF basis) Shareholder flight An incident that causes significant, extensive or long-term (5 years or more) ecological harm. Continuing long-term damage to company reputation. International or government Investigation. Long-term impact on public memory. Total service cessation for a week or more Jail term of any length or fine exceeding $100,000. Major Single fatality and or multiple serious injuries Financial cost or exposure exceeds $10M (DCF basis). Share value stagnation, shareholder dissatisfaction. An incident which causes significant, but confined ecological harm over 1-5 years. Local TV news headlines and/or regulator investigation. Medium-term impact on public memory. Cessation of service to northern or southern areas for a number of days Prosecution of Director or employee Moderate Individual serious injury or multiple/recurring minor injuries Loss or increased costs from $1M to $10M (DCF basis). Significant release of pollutants with mid-term recovery Local press attention and or low profile regulator investigation Cessation of service for over 10% of customer base for more than a week Prosecution of business or prohibition notice. Minor First aid injuries only Loss or increased costs from $50k to $1M (DCF basis) Transient environmental harm Limited local press attention Cessation of service for more than a week Improvement notice. Insignificant No requirement for treatment Loss or increased costs less than $50,000 (DCF basis). An incident which causes minor ecological impacts that can be repaired quickly through natural processes. No impact on public memory Cessation of service for more than a 24hrs Regulator expresses verbal or written concern. Figure E.3- Risk consequences definitions 248

251 APPENDICES 10.4 Appendix D - Emergency Response Plan Table of Contents Related documents ii Table of Contents Purpose, objectives and scope Purpose Objectives Scope Emergency Event Classifications Incident Emergency Significant Event Full Response Event Major Event Response Process Activation Process Emergency Response Team Overview of Emergency Response Team Organisation The Chief Executive Officer (CEO) Emergency Response Manager (ERM) Network Operations Manager (OM) Duty Manager (DM) Control Centre Operators Contracting Services Area Managers (AM) Fault Coordinator(s) (FC) Overseers, Project Supervisors and Senior Foremen Resource Attainment Coordinator (RAC) Faults Administrator(s), (FA) Emergency Response Team (ERT) Default Venues Communications and Reporting Response and Recovery Priorities Response Checklist/Agenda Emergency Response Team Immediate Response Actions First Priority nd Priority Maintenance of Business Continuity Programme Introduction Business Continuity Management Programmed Maintenance Tasks Staff Training Readiness Roles and Responsibilities Emergency Response Manager

252 APPENDICES 10.5 Appendix E Cross References to Requirements of Electricity Information Disclosure Handbook 2004 (as amended 31 October 2008) Handbook Reference Requirement Top Energy AMP Ref Comment Summary i ii The AMP should include a summary that provides a brief overview of the AMP contents. The AMP should highlight information that the EDB considers significant Background and Objectives 4.5.2(a) Purpose Statement i The AMP should contain a purpose statement. 2.2 ii iii The purpose statement should make the status of the AMP clear. The purpose statement should also include the objectives of the EDB s asset management and planning process. These objectives should be consistent with the EDB s vision and mission statements and show a clear recognition of stakeholder interest (b) Interaction with Corporate Goals, Business Planning Processes and Plans i ii iii iv 4.5.2(c) i ii 4.5.2(d) i The AMP should state the EDB s high level corporate mission or vision as it relates to asset management. The AMP should identify the documented plans produced as outputs of the EDB s annual business planning process. The AMP should show how the different documented plans relate to one another with particular reference to any plans specifically dealing with asset management. The objectives of the EDB s asset management and planning processes should be integrated with its other business plan and goals and how well does the AMP describe this relationship. Planning Period The AMP should specifically state that the period covered by the plan is 10 years or more from the commencement of the financial year. The AMP should state the date on which the AMP was approved by the Board of Directors. Stakeholder Interests The AMP should identify the EDB s important stakeholders and indicate (Table 11) Ii - how the interests of stakeholders are identified,

253 APPENDICES Handbook Reference Requirement Top Energy AMP Ref Comment Iii - what these interests are, (Table 11) iv - how these interests are accommodated in the EDB s asset management practices: and (Table 11) v - how conflicting interests are managed (e) Accountabilities and Responsibilities for Asset Management i Ii Iii 4.5.2(f) I Ii Iii iv The AMP should describe the extent of Board approval required for key AMPs and decisions and the extent to which asset management outcomes are regularly reported to the Board. At the executive level, the AMP should provide an indication of how the in-house asset management and planning organisation is structured. At the field operations level, the AMP should comment on how field operations are managed, the extent to which field work is undertaken in-house and the areas where outsourced contractors are used. Asset Management Systems and Processes The AMP should identify the key systems used to hold data used in the asset management process. It should describe the nature of the data held in each system and what this data is used for. The AMP should comment on the completeness or accuracy of the asset data and does it identify any specific areas where the data is incomplete or inaccurate. If there is a problem with data accuracy or completeness, the AMP should disclose initiatives to improve the quality of the data. The AMP should describe the processes used within the business for: managing routine asset inspections and network maintenance, planning and implementation of network development processes, and measuring network performance (SAIDI, SAIFI) for disclosure purposes ,5,3 Assets Covered 4.5.3(a) i High Level Description of the Distribution Area The high level description of the distribution Area should include: - the distribution areas covered, ii - identification of large consumers that have a significant impact on network operations or asset management priorities, iii - description of the load characteristics for different parts of the network, and

254 APPENDICES Handbook Reference Requirement Top Energy AMP Ref Comment iv - the peak demand and total electricity delivered in the previous year, broken down by geographically non-contiguous network, if any. 2.1 Table (b) i Description of the Network Configuration Does the AMP include a description of the network configuration which includes: - identification of the bulk electricity supply points and any embedded generation with a capacity greater than 1 MW, ii - the existing firm supply capacity and current peak load at each bulk supply point, iii - a description of the sub-transmission system fed from the bulk supply points, including identification and capacity of zone substations and the voltage of the sub transmission network, iv - the extent to which individual zone substations have N-x sub-transmission security, v - a description of the distribution system including the extent to which it is underground, vi - a brief description of the network s distribution substation arrangements, vii - a description of the low voltage network, including the extent to which it is underground, and viii - an overview of secondary assets such as ripple injection systems, SCADA and telecommunications systems (Table 10) Table Table Description of the Network Assets i The AMP should include a description of the assets that make up the distribution system that includes, for each asset category: voltage levels, description and quantity of assets, age profiles, value of the assets in each category (which can be drawn from the ODV disclosure or other record bases kept by the EDB), and a discussion of the condition of the assets, further broken down as appropriate and including, if necessary, a discussion of systemic issues leading to premature asset replacement

255 APPENDICES Handbook Reference Requirement Top Energy AMP Ref Comment ii The asset categories discussed at least include: assets owned by the EDB but installed at bulk supply points owned by others, 6 2. sub transmission network including power transformers, 3. distribution network including distribution transformers, 4. switchgear, 5. low voltage distribution network, and 6. description of supporting or secondary systems including: - ripple injection plant, - SCADA, - communications equipment, - metering systems, - power factor correction plant, - EDB owned mobile substations and generators whose function is to increase supply reliability or reduce peak demand, and - other generation plant owned by an EDB (d) Justification for Assets i The AMP should include a justification for the asset base Service Levels 4.5.4(a) i 4.5.4(b) i 4.5.4(c) iii Consumer Oriented Performance Targets Consumer performance targets should be included in the AMP. The targets should be objectively measurable, adequately defined and consistent with the other plans set out in the AMP. Asset Performance and Efficiency Targets The AMP should disclose other targets relating to asset performance, asset efficiency and effectiveness, and the efficiency of the line business activity. Justification for Targets The AMP should include the basis on which each performance indicator was determined. The justification should include consideration of consumer, legislative, regulatory, stakeholder requirements Network Development Planning 4.5.5(a) i Planning Criteria The AMP should describe the planning criteria used for network developments

256 APPENDICES Handbook Reference Requirement Top Energy AMP Ref Comment ii The AMP should describe the criteria for determining the capacity of new equipment for different asset types or different parts of the network (b) Prioritisation of Network Developments 6.2A The AMP should describe the process and criteria for prioritising network developments (c) i ii iii iv v vi 4.5.5(d) i ii Demand Forecasts The AMP should describe the demand forecasting methodology, including all the factors used in preparing the estimates. The demand forecasts should be broken down to at least the zone substation level and do they cover the whole of the planning period. There should be a discussion of the impact of uncertain but substantial individual projects or developments. The extent to which these uncertain load developments are included in the forecast should be clear. The demand forecast should take into account the impact of any embedded generation or anticipated levels of distributed generation within the network. The demand forecast should take into account the impact of any demand management initiatives. The AMP should identify anticipated network or equipment constraints due to forecast load growth during the planning period. Distributed Generation The AMP should describe the policies of the EDB in relation to the connection of distributed generation. Does the AMP discuss the impact of distributed generation on the EDB s network development plans (e) No-network Solutions 6.5A Does the AMP discuss the manner in which the EDB seeks to identify and pursue economically feasible and practical alternatives to conventional network augmentation in addressing network constraints (f) Network Development Plan i The AMP should include an analysis of the network development options available and details of the decisions made to satisfy and meet target levels of service While there is no specific subsection covering this, alternative options are discussed in respect of most network development projects described in this section. 254

257 APPENDICES Handbook Reference Requirement Top Energy AMP Ref Comment ii The AMP should include: - a detailed description of the projects currently underway or planned to start in the next twelve months, Projects due to start in the next 12 months are included in the remaining subsections of Section 5.6. iii - a summary description of the projects planned for the next four years, and iv - a high level description of the projects being considered for the remainder of the planning period. 5.7, 5.8, ,5.8,5.9 v The AMP should discuss the reasons for choosing the selected option for those major network development projects for which decisions have been made to There is a discussion of alternative options and the reasons for selection the preferred alternative in most of these sections. vi For other projects that are planned to start in the next five years, the AMP should discuss alternative options, including the potential for non-network alternatives to be more cost effective than network augmentations to There is a discussion of alternative options and the reasons for selection the preferred alternative in most of these sections (g) Capital Expenditure Budget The AMP include a capital expenditure budget, broken down sufficiently to allow an understanding of expenditure on all main types of development projects Lifecycle Asset Management Planning 4.5.6(a) i Maintenance Planning Criteria and Assumptions The AMP should include a description of the EDB s maintenance planning criteria and assumptions (b) Inspection, Condition Monitoring and Routine Maintenance i The AMP should provide a description and identification of routine and preventive inspection and maintenance policies, programmes, and actions to be taken for each asset category, including associated expenditure projections to 6.22 ii The AMP should describe the process by which defects identified by its inspection and condition monitoring programme are rectified ii The AMP should highlight systemic problems for particular asset types and the actions being taken to address these This information is included, where necessary, in the section related to the relevant asset type. iv The AMP should provide budgets for routine maintenance activities, broken down by asset category, for the whole planning period (c)-(e) i Asset Renewal and Refurbishment The AMP should provide a description of the EDB s asset renewal and refurbishment policies, including the basis on which refurbishment or renewal decisions are made

258 APPENDICES Handbook Reference Requirement Top Energy AMP Ref Comment ii Does the AMP provide a description of the EDB s asset renewal and refurbishment policies, including the basis on which refurbishment or renewal decisions are made, iii - a detailed description of the projects currently underway and planned for the next twelve months, iv - a summary description of the projects planned for the next four years, and v - a high level description of the other work being considered for the remainder of the planning period to to to vi The AMP should include a budget for renewal and refurbishments, broken down by major asset category, and covering the whole of the planning period Risk Management i The AMP should include details of the EDB s risks policies and assessment and mitigation practices including: 7.1 ii - methods, details and conclusions of risk analysis, 7.1 iii - the main risks identified, iv - details of emergency response and contingency plans. V The AMP should identify specific development projects or maintenance programmes with the objective of managing risk. These projects should be discussed and linked back to the development plan or maintenance programmes Evaluation of Performance 4.5.8(a) i ii iii Financial and Physical Progress The actual capital expenditure for the previous year should be compared with that presented in the previous AMP and significant differences should be discussed. The progress of development projects against plan (as presented in the previous AMP) should be assessed and the reasons for substantial variances highlighted. Construction or other problems experienced should be discussed. The actual maintenance expenditure should be compared with that planned in the previous AMP and the reasons for significant differences discussed iv Progress against maintenance initiatives and programmes should be assessed and discussed and is the effectiveness of these programmes noted. 8,9 Top Energy to provide commentary. This could also be included in Section

259 APPENDICES Handbook Reference Requirement Top Energy AMP Ref Comment 4.5.8(b) Service Level and Asset Performance i The measured service level and asset performance for the previous year should be presented for all the targets discussed under the Service Levels section of the AMP. 8. ii There should be a comparison between actual and target performance for the preceding year with an explanation for any significant variances (c) Gap Analysis i The AMP should identify significant gaps between targeted and actual performance. If so, it should describe the action to be taken to address the situation (if not caused by one-off factors). 8 ii The AMP should review the overall quality of asset management and planning within the EDB and discuss any initiatives for improvement Expenditure Forecast Reconciliations and Assumptions i The AMP should include: a) forecasts of capital and operating expenditure for the minimum ten year asset management planning period 9.1 ii b) reconciliations of actual expenditure against forecasts for the most recent financial year for which data is available. 9.2 iii iv v The AMP should identify all significant assumptions that are considered to have a material impact on forecast expenditure (capital or operating) for the planning period Significant assumptions should be presented and discussed in a manner that makes their source(s) and impact(s) understandable to electricity consumers. The AMP should identify assumptions that have been made in relation to the sources of uncertainty

260 APPENDICES 10.6 List of Figures Figure 1: 2011 Asset Management Plan Review Rankings... 1 Figure 2: Top Energy Sub-transmission lines (33kV) and transmission Transpower (110kV)... 8 Figure 3: Network Summary (as at 31 March 2011 unless otherwise shown)... 9 Figure 4: Value of System Fixed Assets... 9 Figure 5: Map of uneconomic lines Figure 6: Causes of interruptions Figure 7: Historical and YE2011 SAIDI performance Figure 8: Historical and Current SAIFI performance Figure 9: Service Level Targets 2012 to Figure 10: Major Project Implementation Timeline Figure 11: Completed Architecture FYE2021 (forecast) Figure 12: Expenditure Forecast (FYE 2011 to FYE2022) Figure 13: Expenditure Forecast Breakdown FYE Figure 14: FYE 2011 Regulated electricity lines business return on investment Figure 15: FYE 2011 Regulated electricity lines business: Annual Line Charges per ICP Figure 16: Network parameters (as of 31 March 2011 unless otherwise shown) Figure 17: Relationship between Stakeholders and AMP Figure 18: Top Energy Structure Figure 19: Top Energy Network Division - Structure Figure 20: Top Energy Network Division Responsibilities Figure 21: Top Energy order approval levels Figure 22: Maintenance planning information flows Figure 23: Screenshot of the Faults Whiteboard Figure 24: Top Energy area of supply Figure 25: Present Zone Substation Transformers Figure 26: Present Zone Substation Transfer/Switching Capabilities Figure 27: Distribution Transformer Population Figure 28: Geographic diagram of the Pukenui zone substation Figure 29: Geographic diagram of the Taipa zone substation Figure 30: Geographic diagram of the NPL zone substation Figure 31: Geographic diagram of the 33kV Okahu Road zone substation Figure 32: Geographic diagram of the Kaikohe zone substation Figure 33: Geographic diagram of the Waipapa zone substation Figure 34: Geographic diagram of the Mt Pokaka zone substation Figure 35: Geographic diagram of the Haruru zone substation Figure 36: Geographic diagram of the Kawakawa zone substation Figure 37: Geographic diagram of the Omanaia zone substation Figure 38: Geographic diagram of the Moerewa zone substation Figure 39: Value of System Fixed Assets

261 APPENDICES Figure 40: Age profile of sub-transmission overhead conductors Figure 41: Age profile of distribution overhead conductors Figure 42: Age profile of low voltage overhead conductors Figure 43: Age profile of sub-transmission poles Figure 44 Age profile of distribution poles Figure 45 Age profile of low voltage poles Figure 46: Age profile of distribution underground cables Figure 47: Age profile of low voltage cables Figure 48: Age profile of distribution transformers (all capacities) Figure 49: Age profile of SWER isolating transformers Figure 50: Age profile of reclosers Figure 51 Age profile of regulators Figure 52: Age profile of ring main units Figure 53 Age profile of sectionalisers Figure 54 Age profile of capacitors Figure 55: Power transformers installed at zone substations Figure 56 Age profile of sub-transmission circuit breakers Figure 57: Age profile of distribution voltage circuit breakers Figure 58: Type and location of 11kV circuit breakers Figure 59 Age profile of batteries and chargers Figure 60: Age profile of substation buildings Figure 61 Age profile of customer service pillars Figure 62 Repeater tower sites Figure 63 Conductor transmission capacity Vs distance Figure 64 Quality Boundary Values Figure 65 Network Sub transmission and Distribution SAIDI Glideslope Figure 66 Network SAIDI Glideslope with the addition of the Transmission Assets Figure 67: Customer Service Level Targets Figure 68: Historical SAIDI performance Figure 69: Historical SAIFI performance Figure 70: Breakdown of line faults Figure 71 Loss Ratios of Top Energy since FYE Figure 72: Loss Ratio Target Levels Figure 73: Top Energy s Operational Expenditure Ratio since FYE Figure 74: Financial Service Level Targets Figure 75: Customer survey Figure 76: Customer expectations - SAIDI Figure 77: Customer expectations - SAIFI Figure 78: Expenditure Forecast (FYE 2011 to FYE2022) Figure 79: Expenditure Forecast Breakdown FYE Figure 80: Security Provided at Zone Substations Figure 81: Top Energy Design Capacity Limits

262 APPENDICES Figure 82: Network Performance Scorecard Figure 83 Example of Network Prioritisation Matrix Figure 84: Zone Substation Demand Forecast (MW) Figure 85: Transmission Substation and Network Demand Forecast (MW) Figure 86: Load Forecast Methodology Overview Figure 87: Distributed generation connection process Figure 88: Emergency Load Shedding Specification Figure 89: Top Energy Emergency Load Shedding Feeder Identification Figure 90: Major Project Implementation Timeline Figure 91: 110kV/33kV line projects Figure 92: Transmission and Subtransmission substation projects Figure 93: Wiroa substation projects Figure 94: Okahu Rd substation projects Figure 95: Pukenui substation projects Figure 96: Taipa substation projects Figure 97: NPL substation projects Figure 98: Kaikohe substation projects Figure 99: Kawakawa substation projects Figure 100: Moerewa substation projects Figure 101: Haruru Falls substation projects Figure 102: Waipapa substation projects Figure 103: Omania substation projects Figure 104: Proposed Kaeo substation projects Figure 105: Proposed Kerikeri substation projects Figure 106: Proposed Purerua substation projects Figure 107: Okahu Rd substation distribution projects Figure 108: Taipa substation distribution projects Figure 109: Kaikohe substation distribution projects Figure 110: Kawakawa substation distribution projects Figure 111: Moerewa substation distribution projects Figure 112: Haruru Falls substation distribution projects Figure 113: Waipapa substation distribution projects Figure 114: Omanaia substation distribution projects Figure 115: Kerikeri substation distribution projects Figure 116: Kaeo substation distribution projects Figure 117: Whatiwhi substation distribution projects Figure 118: Communication/SCADA/Security projects Figure 119: Transmission projects Figure 120: Transmission projects Figure 121: Proposed Infrastructure FYE Figure 122: Top Energy Communications Overlay FYE Figure 123: Core Communications Network Architecture

263 APPENDICES Figure 124: Southern Area Communications Network Architecture Figure 125: Northern Area Communications Network Architecture Figure 126: Voice Network Architecture Figure 127: Voice Network Interim Architecture Figure 128: Pole Top Data Network Architecture Figure 129 Capital Expenditure Category Spend Profile FYE 2013 to FYE Figure 130 Forecast Capital Expenditure FYE 2013 FYE Figure 131: TEN asset inspection programme Figure 132 Information flow chart condition-based assessment Figure 133: Response priority definitions Figure 134 Vegetation Interruption Count Figure 135 Information Flow Vegetation Control Figure 136 Information flow chart earth testing and remediation Figure 137: Maintenance Driven Expenditure by Category Figure 138: Breakdown of Asset Replacement and Renewal Capital Expenditure Figure 139: Risk management review and reporting cycle Figure 140 Top Energy risk management process Figure 141: Risk process main elements Figure 142: Top ten risks identified Figure 143: Network reliability performance (YTD Performance as per end December 2011) Figure 144: Network reliability performance Figure 145: Network reliability statistics Figure 146 Interruptions/SAIDI/SAIFI Contribution by Cause Figure 147 SAIDI performance trends for FYE Figure 148: Top Energy Network Performance Summary of Financial Year Figure 149 Monthly SAIDI performance trends for FYE 2011 and FYE Figure 150 SAIDI performance by 33kV feeder Figure 151: Top Energy Network Worst Performing 33kV Feeders FYE Figure 152 SAIDI performance by 11kV feeder Figure 153: Top Energy Network Worst Performing 11kV Feeders FYE Figure 154: Top ten worst ranking feeders Figure 155 SAIDI for Class B and C Interruptions (FYE 2011) Figure 156 SAIFI for Class B and C Interruptions (FYE 2011) Figure 157: expenditure budget compared to actual Figure 158: Progress on implementing major projects identified in the 2011 AM plan Figure 159 PAS-55 Asset Management System Elements Figure 160 Graphical representation of the 2008 and 2009 Top Energy PAS-55 review results Figure 161 Financial Expenditure Summary Figure 162: Comparison of Actual, Budget and Forecast Expenditure FYE 2011 FYE 2022 by Commerce Commission Category Figure 163: FYE 2011 expenditure Comparison of Budget and Actual Figure 164: Significant assumptions related to the financial forecast

264 262 APPENDICES

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