Asset Management Plan.

Transcription

1 Asset Management Plan

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3 Introduction It gives me great pleasure to present Top Energy Ltd s Network Asset Management Plan (AMP). The 2011 plan continues directly from the 2010 plan in addressing the key issues of reliability, security of supply and capacity, by implementing a reliability improvement programme and a significant sub-transmission investment plan, over the next decade. This AMP is the core asset management planning and operations document for Top Energy and details the 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 Disclosure Requirements whilst also providing detailed information about Top Energy s asset management and planning processes. As a result of the major reliability programme introduced in 2009, 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, we have made a significant improvement in the performance of the network in two years. As of writing, customers in the Far North on average, have experienced 435 SAIDI minutes without power over the last year, reduced from the 924 (54%) in FYE2009 and 463 (7%) in FYE It is planned that reliability improvement will continue to supplement the step changes in performance improvement as a result of the Network Development Plan to deliver a target of 200 SAIDI minutes by The 2010 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. In this AMP, we are pleased to announce that we are also planning 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. Although the Top Energy network investment programme detailed within this AMP is focused on providing sub-transmission capacity for expansion and security of supply for Far North customers, there has still been significant dissatisfaction expressed by customers in the Kaitaia district in relation to the lack of transmission security and the loss of supply which has occurred in recent years. 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 and this has resulted in complaints to the Minister for Energy, with customers demanding the construction of a second transmission line. Customer consultation carried out during 2009 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 This support was used as evidence for an application to the Electricity Commission (now Electricity Authority) for permission to construct a second 110kV circuit between Kaikohe and Kaitaia. 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. The least cost technical solution for a second transmission line to Kaitaia was found to be a re-design to 110KV of the proposed Top Energy 33KV line, along a coastal route. This proposal represents a $10 million saving over the direct route proposed by Transpower. A new transmission line around the coastal route would not only achieve the capacity and security of supply requirements of the existing 33kV plan but would have 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 would provide a security of supply benefit to 24,

4 (80%) of the network s customers rather than just the 10,800 (35%) that would have benefited from a direct Transpower 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 Kaikohe and Kaitaia would be under different ownership. This would make both transmission pricing and operational control very difficult to manage. Transpower has therefore agreed to transfer its existing assets in the Far North to Top Energy, whilst Top Energy constructs the second transmission line to Kaitaia. The transfer, which is planned to take place later in FYE2012, 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 transmission 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 equipment, 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. Both the transmission asset transfer and the construction of a new 110 kv circuit around the East Coast, together with the planned Transpower capital investment works, will have a major impact on the detailed design and timing of the sub-transmission development plan that is already in place. These changes, which are dependent on this transfer proposal being approved by the Commerce Commission, are still being formulated and so, are not described in great detail in this AMP. Assuming the east coast transmission option is approved and the transmission asset transfer proceeds, the 2012 AMP will present an integrated development plan, covering the planned development of both transmission and sub-transmission assets. 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 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 O b j e c t i v e s Overview Scope of the Plan Purpose of this Plan Rationale for Asset Ownership Strategic Environment for Asset Management Planning Related Documents Contributing to the Annual Business Planning Process Asset Management Systems Business Processes and Information Flow Requirements A s s e t D e s c r i p t i o n Overview Asset Details by Category Justification for Assets L e v e l o f S e r v i c e Introduction Customer Orientated Service Levels Asset Performance and Efficiency Targets Justification for Service Level Targets N e t w o r k D e v e l o p m e n t P l a n n i n g Planned Expenditure Planning Criteria Distribution Policy on Acquisition of New Assets Project Prioritisation Methodology Demand Forecast Network Development Plan Transmission Development Plan Network Development Plan

6 5.10 Detailed Project Descriptions and Development Timeline L i f e c y c l e A s s e t M a n a g e m e n t Maintenance and Renewal Planning Criteria and Assumptions Overhead Conductors Poles and Structures Underground & Submarine Cables Distribution & 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 & Communications Load Control Plant Total Maintenance and Renewal Expenditure Forecast R i s k M a n a g e m e n t Risk Management Policy Risk Mitigation E v a l u a t i o n o f P e r f o r m a n c e Introduction Review of Performance against Targets Asset Management Improvement Programme E x p e n d i t u r e F o r e c a s t year forecast of capital and operational expenditure Reconciliation of actual expenditure against expenditure for Yr Significant assumptions A p p e n d i c e s Appendix A Nomenclature Appendix B Typical Zone Substation Arrangements Appendix C 2009 Customer Consultation Survey Questions Appendix D Feeder Load Growth Appendix E Risk Management Framework

7 10.6 Appendix F- Service Level Indicator Analysis Appendix G - Emergency Response Plan- Table of Contents List of Tables List of Figures

8 EXECUTIVE SUMMARY Section 1 Executive Summary 1. E x e c u t i v e S u m m a r y Company Background New 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 almost 32,000 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 Northland region. It 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 Over the period 2010 to 2020, Top Energy is planning to make a significant investment in its aging and historically unreliable electricity network assets. The key drivers are to improve the operational performance, improve the security of supply and improve the service provision to electricity consumers on the Top Energy electricity network. The last three years has seen a steady decline in Top Energy s network performance to become the worst performing company in New Zealand for network reliability. During , on average, each customer experienced four outages and almost eight hours without electricity. Whilst this performance can be viewed as a 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 instigated to mitigate the factors as far as is economically practicable. A large part of the key challenges in security of supply and performance can, to some degree, be explained by the fringe location of the network and the limitation that is afforded by only having two grid exit points (GXP s) from Transpower s national grid, when a large rural network of this size would usually have many more. This design harks back to 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 the areas of Kerikeri, the Bay of Islands and the eastern coastal peninsulas. Some parts of the network, which were previously considered fringe coastal communities, are now operating at over 90% of capacity, during peak periods. This dramatic change in socio-economic dynamics severely limits the ability to connect new customers as well as restoring supplies to existing customers when a fault occurs. To address these issues and to improve security of supply, Top Energy will invest over $200M during the next decade in what will be the single largest expansion in the history of the Top Energy electricity network. The work will expand and strengthen the 33kV sub-transmission system in order to effectively increase the number of bulk supply points at which power is injected into the older distribution network. Key projects that are identified within this plan include seven new zone substations and over 200km of new 33kV line construction. The result of this expansion will be a significantly more secure and reliable network to support the future economic growth of the Far North. Top Energy is also currently seeking regulatory approvals that will enable it to acquire from Transpower the assets at the Kaikohe and Kaitaia grid exit points and the existing 110 kv single circuit line between the two substations. Should these be granted, it is anticipated that the asset transfer will occur in the second half of FYE2012. The acquisition of these assets will allow Top Energy to construct a second 110 kv line between Kaikohe and Kaitaia over a new route around the Eastern Bays. Not only would such a line address the major security issue faced by consumers in the Far North; it will also provide additional security to consumers in the Eastern Bays by permitting the supply into this area to be sourced from either Kaitaia or Kaikohe. The construction of a 110 kv line around the Eastern Bays will impact the planned development of the subtransmission network, by providing opportunity for more points of injection from 110 kv. The detail of these impacts has still to be finalized. As a result, the construction of the new 110 kv line and any associated 7

10 EXECUTIVE SUMMARY substations has not been allowed for in this AMP. Should the 110 kv asset transfer be finalised, changes to the sub-transmission plan to accommodate the availability of a 110 kv supply around the Eastern Bays will be described in the 2012 AMP. Sub-transmission and bulk supply capacity is not the only focus for strategic investment; vegetation control together with the distribution network s ability to withstand adverse weather events presents a number of opportunities for significant performance improvement. In April 2009, we began a major reliability programme targeting the clearance of trees and vegetation near lines. We also installed specialist 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 each fault event. Overall, the results have been excellent. Network SAIDI has reduced from over 900 minutes in to 464 in The number of outages experienced by our consumers more than halved over 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. The work planned over the next decade will also have a significant impact on the human resource at Top Energy. An initial recruitment campaign for around 35 planners, project managers, electrical lines engineers and other staff was launched in January Further recruitment will take place to support the delivery of the AMP and around 20 new permanent positions may arise from the investment in the electricity network operation over the planning period. 8

11 1.3 Network Description EXECUTIVE SUMMARY 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 1 Top Energy Sub-transmission lines (33kV) and transmission Transpower (110kV) DESCRIPTION Area Covered QUANTITY 6,822 km2 Customer Connections ( 31/03/10) 30,824 Supply points from Transpower Kaitaia GXP Peak Demand Kaikohe GXP Peak Demand Ngawha Peak Generation Combined peak Demand 2 : Kaitaia and Kaikohe 24.8 MW 45.4 MW 25.0 MW 70.2 MW Number of Distribution Feeders 46 Distribution Transformers (Including SWER) (as at 31/3/10) Sub transmission Cables (33kV) Sub transmission Lines (33kV) HV Distribution Cables (22,11,6.35kV) HV Distribution Lines (22,11,6.35kV) 5, km 263km 160km 2099km Table 1 Network Summary (as at 31 March 2011 unless otherwise shown) 9

12 EXECUTIVE SUMMARY 1.4 Value of Network A summary by asset category per the last audited Optimised Deprival Valuation (ODV) in 2004 is shown in the table below. Table 2 Optimised Deprival Valuation (ODV) summary as at 2004* *NOTE: The next audited ODV was due for publishing in 2007; however, this was postponed as the Commerce Commission was in the process of consultation with Electricity Distribution Businesses on the valuations of their Distribution Assets. At the time of writing, the date for the next full ODV revaluation is yet to be confirmed, although there is the requirement for Distribution Lines Companies who are following a Regulatory Default Price Path to review and update their 2004 ODV valuation in 2011 as part of the Regulatory Input Methodologies. The overall level and accuracy of asset data has improved significantly since 2004 which will result in improved accuracy of the next valuation. The disclosed regulatory value of the network asset base was $ million as at 31 March Areas of Uneconomic Supply During late 2008, the Electricity Networks Association (ENA) established a working party to review the implications of a 2007 governmental review of Section 62 of the Electricity Act 1992 (the Act). The changes to the Act are significant in that it continues to force lines companies to supply line services to customers after the requirement in the original Act expires on 1 April 2013, even though they may reside in areas that it is not economic for the company to continue to maintain supply to. In this regard, the affect on Top Energy is significant. 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. In April 2009, Top Energy engaged Intergraph to assist in identifying uneconomic lines using GIS data that related to the Ministry of Economic Development s suggested test scenarios. The project analysed each piece of equipment within the GIS system, feeder by feeder and 10

13 EXECUTIVE SUMMARY identified where uneconomic lines began. The start points were individually recorded and each of these became the beginning point of a further trace, which in turn identified all downstream equipment, and summarised the length of uneconomic conductors. The collated results revealed that 32.38% of Top Energy lines, which feed approximately 7.97% of the Top Energy customer base, are uneconomic. Under the changes to the Act, Top Energy is responsible for the ongoing maintenance, repair and upgrade of these lines after 1 April 2013, even though the cost of service will never be recovered through line charges to the supplied customers. As a result, unless customers in uneconomic areas agree to disconnect from the grid in favour of alterative generation, higher charges will need to be levied across the entire Top Energy customer base. The following table details the results for each individual zone substation applyng the criteria of less than 20kVA per Individual Connection Point (ICP) and less than 3 ICP per kilometre (km) of line. ZONE SUB UNECNMC LENGTH TOTAL LENGTH % LENGTH UNECNMC UNECNMC CUSTOMERS SUPPLIED TOTAL CUSTOMERS SUPPLIED % CUSTOMERS UNECNMC Kaikohe Kawakawa Moerewa Waipapa Omanaia Haruru Okahu Rd Taipa Pukenui NPL Total Table 3 Top Energy zone substation uneconomic feeder statistics 11

14 EXECUTIVE SUMMARY Figure 2 Map of uneconomic lines 1.6 Reliability In the Financial Year Ending (FYE) 2010, Top Energy s SAIDI minutes (System Average Interruption Duration Index) was a value of minutes. This reduced to minutes when the SAIDI impact of major storm events is excluded. Compared with the FYE2009 performance of SAIDI minutes, this is a remarkable result and is our best performance since FYE2007. The overall network quality performance for FY2010 resulted in a total of: kV and 33kV Top Energy faults, and Top Energy planned outages, resulting in o minutes of SAIDI, and o 4.19 customer interruptions (SAIFI). The table overleaf shows that the most significant causes of unplanned interruptions were adverse weather, tree contacts, lightning and defective equipment: 12

15 EXECUTIVE SUMMARY Interruption CURRENT % Equipment Failure 21.4% Adverse Weather 12.76% Vegetation Related 12% 3rd Party 9.44% Animals 7% Lightning Related 1.6% Transpower 0.4% Planned 35.4% Table 4 Causes of interruptions Equipment failure had most significant impact on network performance with the exception of Planned Outages for FY2010. Top Energy did not breach its reliability threshold during FYE2010, despite a major event that occurred on 12 th July This storm contributed approximately SAIDI minutes to the annual SAIDI total. The summary of FY2010 network performance before and after the exemption is listed in the table below. FINANCIAL YEAR 2010 YE SAIDI (MINUTES) YE SAIFI Regulatory Quality Threshold Regulatory Quality Threshold Impact of Major Event Days 12 th July Storm Event Total Impact Request for Exemption based on the Guideline Year End Top Energy Actual Performance Pre Exemption Post Exemption SAIDI (mins) SAIFI Below Regulatory Quality Threshold by Below Regulatory Quality Threshold by Table 5 FY2010 network performance 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 13

16 EXECUTIVE SUMMARY meet regulatory performance thresholds for SAIDI and SAIFI, covering interruptions originating from its network for both planned interruptions (Class B) and unplanned interruptions (Class C). The following figures show Top Energy s historical 10 year performance for both of these measures. The increase in Regulatory Threshold values for FYE2010 is reflective of the recalculation at the commencement of a new 5 year Price / Quality Regulatory regime on 1st April SAIDI SAIDI THRESHOLD Figure 3 Historical and YE2010 SAIDI performance SAIFI SAIFI THRESHOLD Figure 4 Historical and YE2010 SAIFI performance 14

17 EXECUTIVE SUMMARY INTERRUPTION FYE2009 % FYE2010 % TARGET 2015 % Vegetation Related 52% 12% 5% Adverse Weather & Lightning 21% 14% 2.5% Equipment Failure 9% 21% 5% Animals 4% 7% 2.5% Planned 9% 35% 50% 3rd Party 4% 9% 15% Transpower 1% 0.5% 20% Table 6 Breakdown of interruptions Targets have been set to: Reduce Vegetation Faults to < 30 Faults per year (Currently 54) Reduce Lightning Faults to < 5 per year (Currently 7) Reduce Equipment Failure Faults to < 25 (Currently 96) Monitor and Target performance in line with an established Peer Group of Lines Companies To successfully achieve these performance improvements, Top Energy is targeting significant expenditure in the areas of vegetation control, lightning protection, network automation, live line working, modern protection systems and condition based maintenance strategies. As shown in the figures above the success of these strategies is readily apparent in the much improved reliability achieved in YE2010. Top Energy anticipates even further improvements in reliability as the strategies set out in this plan are progressively implemented. Consistent with decisions taken by the Commerce Commission in setting the quality thresholds that will apply to the regulatory period 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. 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 as follows: OPERATIONAL PERFORMANCE TARGET SAIDI (minutes) 370 SAIFI (no of interruptions) 4.5 FINANCIAL TARGET Operational Expenditure Ratio 4.75% TECHNICAL TARGET LOSS RATIO 8% Table 7 Service Level targets 15

18 EXECUTIVE SUMMARY 1.7 Network Development Plan Extensive work was carried out between 2009 and 2010 on developing an optimised, justifiable and technically feasible solution to the current network security, capacity and reliability issues. In particular there are a raft of capacity and security of supply issues present on the 33kV network that will require significant and targeted investment over the course of the next ten years to rectify. The development strategy detailed within this AMP involves: construction of new high capacity overhead lines as well as significant augmentation of the existing 33kV circuits; construction of six new zone substations, two new sub-transmission switching stations and post 2035, a new 110kV grid substation; development and implementation of significantly more advanced and comprehensive protection schemes; and introduction of new Ground Fault Neutraliser technology at all zone substation sites. Top Energy undertakes to achieve security of supply standards that are relevant to the size and criticality of customers or customer groups. Top Energy s network security standards are in most cases not achieved at zone substation level. This means that faults on the 33kV system will cause customer outages for unacceptably long periods of time. Similarly, supply quality largely dependent on the availability of capacity within the network to provide customer load demands. If instantaneous demand levels exceed available capacity then supply quality will fall outside statutory limits. The current capacity of some sections of the Top Energy network means that voltage issues will become critical on parts of the network by The 33kV system supplying the southern area of Top Energy s network, and the Eastern Bays in particular, is of insufficient capacity to meet projected demand at the end of the planning period and will be unable to maintain voltage stability in and around Kerikeri beyond Capacity constraints have necessitated the configuration of the network so that power supply is via single 33 kv lines, resulting in supply outages to a large number of customers under fault or outage conditions on the 33kV system. The required network development is being undertaken in a staged fashion, with the commissioning of projects timed to coincide with capacity or security limits being reached. Construction has commenced on a new 110kV line between Kaikohe and Wiroa which will alleviate the capacity constraint around Kerikeri. This new line will provide stepped increases in capacity by being operated for the first 20 years or more of its life at 33kV, thus deferring significant investment in a 110kV substation for that period of time. Capacity issues are not as critical in the north of Top Energy s network and therefore capacity reinforcement, where it is found necessary, is planned for the latter part of the 10 year planning period. This timing enables resources to be focused in the south. The proposed Karikari Peninsula substation is a good example of this. Although it is uncertain whether the project will eventuate within this planning period, it is felt that the progressive load growth around the eastern to northern bays will require the construction of the new substation around 2021 or soon thereafter.however, the development itself is flexible, and not reliant on the completion of other associated works. Therefore should the local area experience accelerated growth, then the project can be bought forward within the planning period and other works deferred to allow for resource balancing. The most significant issue for the northern region is the single circuit supply from Transpower rendering the whole region N security (single line with no alternatives or redundancy) at 110kV. Zone substation security of supply issues; however, follow the same pattern as in the South. The Network Development Plan for the north centres on line security and involves the upgrade of existing and construction of new 33kV lines to Pukenui and Taipa, in addition to a north / south interconnection from Taipa to Kaeo. A new substation at Karikari will support the anticipated load growth on the peninsular. Top Energy is currently seeking regulatory approvals that will enable it to acquire from Transpower the Kaikohe and Kaitaia grid exit points and the existing 110 kv single circuit line between the two substations. Should these be granted, it is anticipated that the asset transfer will occur in the second half of FYE2012. The 16

19 EXECUTIVE SUMMARY acquisition of these assets will allow Top Energy to construct a second 110 kv line between Kaikohe and Kaitaia over a new route around the Eastern Bays. Not only would such a line address the major security issue faced by consumers in the Far North; it will also provide additional security to consumers in the Eastern Bays by permitting the supply into this area to be sourced from Kaitaia or Kaikohe. The construction of a 110 kv line around the Eastern Bays will impact the planned development of the subtransmission network, by providing opportunities for more points of injection from the 110 kv. The detail of these impacts has still to be finalised. As a result, the construction of the new 110 kv line and associated substations has not been allowed for in this AMP. Should the 110 kv asset transfer be finalized, changes to the sub-transmission plan to accommodate the availability of a 110 kv supply around the Eastern Bays will be detailed in the 2012 AMP. This AMP identifies some 21 core major capital projects that will be required to be undertaken over the planning period to transition the network from its current configuration to the proposed configuration (without the new 110 kv line). This will 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 before the constraints have a negative impact on system performance and customer service. MAJOR PROJECT COST ($M) kV / 110kV line Kaikohe to Wiroa 6.8 Ngawha 33kV line No Kerikeri Substation and Interconnections kV Line Upgrades (incl Waipapa #1 refurbishment) 3.8 Submarine cable to Russell and Interconnections 6 33kV Switchyard and switching station Wiroa 2.55 Waipapa #2 Line refurbishments 1.3 Pukenui 33kV Line No 1 Reconstruction 2.5 Taipa Transformer Replacements 2.5 Purerua Substation and Line Interconnections 9.18 Kaeo Substation and Interconections kV Feeder Conversions - Taheke, Russell, South Rd kv Line Taipa to Kaeo kV line Haruru to Kerikei kv Line No 2 to Pukenui kV line No 2 to Taipa kV line No 2 to Omanaia 3.7 Table 8 Major capital project timeline 17

20 EXECUTIVE SUMMARY Current Network Architecture Kaitaia 110kV Pukenui Okahu Rd Taipa NPL Waipapa Kaikohe 33kV Haruru Ngawha 40 MW Moerewa Russell Maungatapere Kaikohe 110kV Omanaia Kawakawa Figure 5 Network architecture 1 st April 2010 Completed Architecture Kaitaia 110kV Karikari Pukenui Okahu Rd Taipa NPL Wind Farm 90 MW Awanui Kaeo Purerua Wiroa Rd 110kV Waipapa Kerikeri Ngawha 75 MW Kaikohe 33kV M Mt Pokaka Haruru Russell 22kV Moerewa Maungatapere Kaikohe 110kV Omanaia Kawakawa Figure 6 Completed Architecture 1 st April 2035 (forecast) 18

21 EXECUTIVE SUMMARY The graphs below detail the breakdown of expenditure for regulatory cost category comparison. Where possible, projects were 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. 30,000,000 25,000,000 20,000,000 15,000,000 10,000,000 5,000,000 0 Figure Expenditure Forecast (FYE2012 to FYE2021) Operational Expenditure: Fault and Emergency Maintenance Operational Expenditure: Refurbishment and Renewal Maintenance Operational Expenditure: Routine and Preventative Maintenance Capital Expenditure on Non- System Fixed Assets Capital Expenditure: Asset Relocations Capital Expenditure: Asset Replacement and Renewal Capital Expenditure: Reliability, Safety and Environment Capital Expenditure: System Growth CAT EXPENDITURE DESCRIPTION FYE 2012 FORECAST ($K) CU Customer Connections 1,000 EX System Growth 6,686 RS Reliability, Safety and Environment 5,392 RR Asset Replacement and Renewal 4,085 RL Asset Relocations 175 Capital Expenditure on Asset Management 17,338 Capital Expenditure on Non-System Fixed Assets 1,250 MP Routine and Preventative Maintenance 4,100 MR Refurbishment and Renewal Maintenance 1,078 F Faults 900 Operational Expenditure on Asset Management 6,078 Total Expenditure 24,666 Table 9 Expenditure Forecast Breakdown FYE

22 Wellington Electricity WEL Networks Vector Lines Limited Aurora Energy Horizon Energy Distribution OtagoNet Joint Venture Powerco Limited Waipa Networks Limited Unison Networks Network Tasman Limited Nelson Electricity Limited Orion New Zealand Eastland Network Network Waitaki Limited Alpine Energy Limited Electricity Invercargill Electricity Ashburton Buller Electricity Mainpower New Zealand Scanpower Limited Northpower Limited Centralines Limited The Lines Company The Power Company Westpower Limited Top Energy Limited Counties Power Marlborough Lines Limited Electra Limited EXECUTIVE SUMMARY With effect from 1st February 2010, Top Energy increased its distribution line charges by an average of $15 (20%) across the tariff groupings to assist with funding the investment in network security of supply, performance and capacity improvements over the planning period. With effect from 1st February 2011, Top Energy has further increased its distribution line charges by an additional (average) 3.4% across the tariff groupings, in line with CPI increments allowed under the Regulatory Default Price Path between 1 st April 2010 to 1 st April In 2010, revenue models indicated that, to achieve a Return on Investment (ROI) equivalent to the Weighted Average Cost of Capital (WACC) for the network business alone, Top Energy needed to increase distribution line charges by approximately by 47%. This was considered to be an unrealistic burden for the region s consumers to bear. As an alternative, Top Energy increased its borrowings, sold and leased back operational premises, and applied a group subsidy from the generation business that resulted in the price increase being held to the considerably lower level of 20%. Sinclair Knight Mertz was engaged to complete an independent review of the Top Energy investment plans, both in terms of required work and the budget estimates. They confirmed the work was unquestioningly required and that the costs were in line with their expectations. They then reported their findings in a letter to the Top Energy Chairman and Board of Directors. From a regulatory point of view, a key driver around the timing of the price increase was the uncertainty around the forward price path in terms of when Top Energy would get a definitive view from the Commerce Commission on what the allowable regulated price path for Top Energy would be. As a result of its financial modelling, Top Energy has developed the view that a Customised Price Path tailored to Top Energy s particular requirements would be required to fund the network investment over the next decade. However to meet capacity and security of supply time constraints, the investment plan is required to commence in FYE2010 and cannot be delayed until a customised price path framework is determined. Instead, Top Energy has elected to take a conservative view on what the allowable ROI is likely to be and increased prices to that level, prior to the change in the regulatory framework. As a result, the relative ROI did not change when compared to other regulated companies and remains at the lower end of the band that Top Energy believes will be defined by the regulator (7-9% ROI). 14.0% 12.0% 10.0% 8.0% 6.0% 4.0% 2.0% 0.0% Figure 8 FYE2010 Regulated electricity lines business return on investment 20

23 OtagoNet Joint Venture Electricity Ashburton Westpower Limited The Power Company Buller Electricity The Lines Company Horizon Energy Distribution Eastland Network Alpine Energy Limited Centralines Limited Marlborough Lines Limited Mainpower New Zealand Network Waitaki Limited Vector Lines Limited Orion New Zealand Unison Networks WEL Networks Northpower Limited Nelson Electricity Limited Powerco Limited Network Tasman Limited Scanpower Limited Wellington Electricity Aurora Energy Electricity Invercargill Top Energy Limited Waipa Networks Limited Counties Power Electra Limited EXECUTIVE SUMMARY In addition, this increase does not affect Top Energy s position for annual line charges per ICP when compared to its peer group of companies, highlighted green below. (i.e. less than 10 customers per km). $2,000 $1,800 $1,600 $1,400 $1,200 $1,000 $800 $600 $400 $200 $- Figure 9 FYE2010 Regulated electricity lines business: Annual Line Charges per ICP Further detailed discussion and analysis behind the development of this plan, together with individual project descriptions, cost estimates and justifications; have been provided within sections 5, 6 and 9 of this plan. 21

24 BACKGROUND AND OBJECTIVES Section 2 Background and Objectives 2.1 Overview Scope of the Plan Purpose of this Plan Rationale for Asset Ownership Strategic Environment for Asset Management Planning Related Documents Contributing to the Annual Business Planning Process 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

25 BACKGROUND AND OBJECTIVES 2 Background and Objectives 2.1 Overview Top Energy Limited, formed in 1993, 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. The group is 100% owned by the Top Energy Consumer Trust. The Trust's purpose is to hold the shares in the Company on behalf of power consumers connected to Top Energy's local electricity network and to distribute the benefits of ownership to those consumers as a group, irrespective of which energy trading company they may purchase their electricity requirements from. Top Energy Limited s Network Division (TEN) is the local Electricity Distribution Lines Business (ELB) that supplies approximately 30,000 electricity consumers in the Mid and Far North of New Zealand's North Island. Its predecessor, the Bay of Islands Electric Power Board was first established in Top Energy Ltd is a major contributor to the community's financial well-being, managing assets in excess of $300M (million) and employing approximately 200 staff. The Company is one of the largest in the region and is uniquely placed to act as a catalyst to develop the region s economic potential. Not only does the Company s asset base provide the necessary basis to lead new projects but the experience and knowledge of its existing staff provide a base from which new staff can be trained to deliver quality results to customers. 2.2 Scope of the Plan This AMP covers all of TEN s electricity lines and substation assets, which are located in an area from south of the Bay of Islands and the Hokianga Harbours to the northern tip of the North Island of New Zealand. The assets encompass a 33kV sub-transmission network that takes supply from two Transpower Grid Exit Points (GXPs) located at Kaikohe and Kaitaia and also from the Ngawha Geothermal Generation Plant. The sub-transmission system supplies eleven zone substations, which in turn supply forty-six distribution feeders. The table below shows the network parameters as at 31 st March DESCRIPTION QUANTITY Area Covered 6,822 km 2 Customer Connection Points (as at 31/3/ 2010) 30,824 Grid Exit Points Embedded Generator Injection Points Kaikohe GXP Peak Demand Kaitaia GXP Peak Demand Ngawha Peak Generation Network Peak Demand to 2 : Kaitaia and Kaikohe 1 : Ngawha Geothermal 45.4 MW 24.8 MW 25.0 MW 70.2 MW Number of Distribution Feeders 46 Number of Distribution Transformers (Including SWER) (as at 31/3/10) 5,933 Sub transmission Cables (33kV) Sub transmission Lines (33kV) HV Distribution Cables (22,11,6.35kV) HV Distribution Lines (22,11,6.35kV) 0.5 km 263km 160 km 2,099 km 23

26 BACKGROUND AND OBJECTIVES Table 10 Network parameters (as of 31 March 2011 unless otherwise shown) In addition to Top Energy owned sub-transmission and distribution network assets, the AMP also takes into account assets owned by Transpower where transmission system development impacts on the company s service level objectives. This AMP does not include the generation assets owned and operated by Top Energy s subsidiary company, Ngawha Generation Ltd, which owns and operates the 25MW Ngawha Geothermal power station located seven kilometres from Kaikohe. 2.3 Purpose of this Plan This AMP is a living document within Top Energy and lies at the heart of the asset management process of the company. It is the integral tool for managing the long term capital and maintenance activities of Top Energy. 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 costeffective 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; to translate Top Energy s business objectives and strategic goals into asset management strategies and action plans as they relate to the distribution network. The plan identifies forward works programmes required to meet agreed service levels and cater for future growth and estimates the current cost of delivering these programmes; to demonstrate responsible management of the network infrastructure to stakeholders, ensuring that funds are optimally applied to deliver cost-effective services that meet customer expectations; to document current asset management practices used by TEN as part of a sustainable and optimised lifecycle management strategy for the network infrastructure and identify actions planned to enhance management performance; and to 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 the Group s network business and sets out 10-year capital and maintenance expenditure levels that have been estimated to be required to ensure the network is managed in a sustainable way. The AMP also includes Top Energy 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 manages its assets responsibly. The AMP also sets out macro-level strategies for the various asset classes for the planning period. Changes and modifications will be made to the plan to reflect the dynamic nature of the business. Top Energy s protection of stakeholder interests is achieved through the application of business management and risk management processes founded in the 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 strategies reflect the views of stakeholders including customers; meeting legal and regulatory requirements are an integral part of the business; 24

27 BACKGROUND AND OBJECTIVES a long term view is taken to developing annual budgets and work plans; asset strategies support revenues and deliver a reasonable profit in keeping with both shareholder expectations and regulatory requirements; 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 ethical behaviour is practised in everything that is done, particularly during all stakeholder interactions. 2.4 Rationale for Asset Ownership The assets covered by this AMP are used 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 by a limited number of zone substations. Extensive use is made of two wire and single wire earth return lines. Today, the availability of an electricity supply is taken for granted and consumers are becoming increasingly concerned about reliability. However, the existing network was never designed to supply the level of reliability consumers now expect. While there have been recent improvements as a result of better maintenance practices and the installation of strategically targeted network automation and remote control devices, the overall reliability of supply from the existing network remains amongst the lowest in the country. The existing asset base is still not adequate to provide the level of supply reliability that is now taken for granted in a modern developed economy. In order to significantly improve supply reliability, the network needs to be upgraded, primarily by providing more points of injection into the medium voltage distribution system. This would have the following benefits: It would increase the utilisation of the existing medium voltage network assets; It would improve the reliability of supply by allowing 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. It would improve network voltages, which would increase the quality of supply to customers in remote areas. The upgrade requires the construction of more zone substations and reinforcement of the existing transmission and subtransmission networks. Section 5 of this AMP presents an ambitious 10-year network development plan that, when completed, will provide a network with sufficient capacity to meet electricity demand in the Far- and Mid-North in the medium term and beyond. 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 ensure the ongoing economic development of its supply area. 2.5 Strategic Environment for Asset Management Planning The Statement of Corporate Intent (SCI) records the strategic Corporate Mission Statement of Top Energy as 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 asset management are: 25

28 BACKGROUND AND OBJECTIVES achieving network service quality standards acceptable to the community and deliverable from future maintainable earnings of the network business; 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 consistent with those adopted in the AMP and there is a focus on financial and environmental sustainability, safety and community responsibility. In terms of the SCI corporate objectives, the following business objectives have been adopted in the Strategic Planning Review and provide a framework for asset management at Top Energy: 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 appropriatepeer 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. 2.6 Related Documents Contributing to the Annual Business Planning Process The company maintains a number of internal and external planning documents that connect with the AMP. The more important of these are: the SCI, which is agreed between the Trustees and the Directors on an annual basis. This document outlines the Company s strategic performance targets. the Strategic Planning Review, which outlines the business activities that Top Energy is involved in and contains high-level details on the business environment and the planned strategies for each area of activity; the regulatory disclosure documents, including those associated with information disclosure, financial accounts, and the Commerce Commission s price-quality threshold regime; the Risk Management Manual- (the framework and analysis process for the identification and mitigation of business risks across the organisation); the 10-year Network Development Plan, which details the forecast growth in demand for electricity and the planned augmentation of the network to meet this demand; the Network Maintenance Plan, which details the medium to long term maintenance strategies for the network; 26

29 BACKGROUND AND OBJECTIVES the Annual Plan/Budget, which is 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 which they need to be aware of and/or approve; the Emergency Preparedness Plan, which defines Top Energy s network management and associated practices adopted to ensure electricity supply is maintained or quickly restored following emergency circumstances and events; and the Northland Region Civil Defence Emergency Group Plan (NRCDEGP), which describes procedures for the response to a civil defence emergency in the Northland region. 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. The relationship between this AMP and other internal planning documents is shown in Figure 10. While strategic corporate objectives influence the direction of the AMP, the AMP also forms a key input into the detailed corporate planning process. It thus forms an integral part of a circular planning process that determines the strategic direction that Top Energy adopts to optimise the benefits to all stakeholders when assessed over a medium term planning period. The planning process begins with the annual Strategic Planning Review of the company s business carried out by the Top Energy Board and the Executive Management Team. Inputs to the Strategic Planning Review include the Risk Management Manual, the Network Development Plan and the Network Maintenance Plan. The purpose of the review is to determine the operational and financial strategy for the Group at a high level and therefore the longer term strategy for the company. The Strategic Planning Review includes a financial analysis of the position of the network business based on the expenditure requirements set out in the Network Development and Maintenance Plans. The SCI, which is agreed between the Trustees and the Board is prepared in parallel with the Strategic Review and details the key objectives and targets of the network business. These, together with the more detailed development and maintenance strategies set out in the Network Development and Maintenance Plans are reflected within the AMP, which consolidates the information in the internal documents into a single asset management planning document for use by external stakeholders and Top Energy s own staff. The AMP budget for the first year of the planning period is the same as TEN s Annual Budget and Work Plan for that year, while the AMP budget estimates for the remaining years of the planning period are forecasts based on the needs of the network business as reflected in the Strategic Planning Review. The Annual Work Plan is then managed and delivered by the Network Management Team. However, all projects over $500k in value are also subject to individual Board approval before commencement. This is carried out via a detailed project proposal paper being submitted for review. On review, the status of approval/rejection is formally recorded as an item within the monthly Board meeting minutes. The Network 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 reports to the Top Energy Board on a monthly basis. Any material variations to the documented work in terms of scope or financial over-runs are presented to the Board for consideration at the first available monthly meeting. This information together with detailed analysis of the reasons for any over-run is tabled as an amendment to the previously approved board paper. 27

30 BACKGROUND AND OBJECTIVES Variations to projects of less than $500k are generally discussed and agreed between the General Manager Networks and the Chief Executive Officer although they may be raised for Board approval if it is believed to be material to the overall Annual Work Plan. Figure 10 Top Energy Asset Management Document Plan Relationships The key planning documents are reviewed and issued annually according to the following programme: the Strategic Planning Review and the Statement of Corporate Intent are prepared and agreed with the Trustees in June/July; after the load peaks in August, analysis of system loads begins, and forecasting models are updated and studied for capacity and quality issues; annual reviews of the financial and service level performance are initiated in September; 28

31 BACKGROUND AND OBJECTIVES latest asset condition information is used to develop and update maintenance and renewal project schedules in December; industrial customer contracts are reviewed with customers in December; customer surveys are carried out in January when necessary; capital projects are reviewed and updated in January; general tariff reviews take place in December/January; overhead budgeting is carried out in January/February; a completed long and short-term business plan goes to the Board in January with approval provided by end of February, a month prior to the financial year commencement on 1 April; and the Asset Management Plan, the Pricing Methodology and the Network Loss Factor Methodology are published prior to 1 April in accordance with the requirements of the Commerce Commission and Electricity Authority Planning Periods Adopted This AMP is dated 1st April 2011 and relates to the period from 1 April 2011 to 31 March It was approved by the Top Energy Board on 29th March 2011 and replaces all previously published AMPs Key Stakeholders Top Energy identifies stakeholder interests through the following forums: meetings and informal discussions; visits with major customers; industrial seminars and conferences; customer surveys; faults; enquiries and/or complaints; discussions with Trust; reviews of major events (eg storms); network quality of supply studies; specific project consultation (eg capital projects); meetings with suppliers; performance review and management for internal and external contractors; and papers and submissions. The table below indicates how the AMP reflects and helps Top Energy address the expectations of the various 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 stakeholder expectations, the AMP addresses this by aiming for an optimised outcome that is acceptable to all affected stakeholders. Top Energy manages any conflicting stakeholder interests by: consideration of safety as the highest priority; consideration of the needs of stakeholders as part of high level network planning process; a balance between the cost of non-supply and the investment to provide security desired; cost/benefit analysis (eg of quality of supply); and being guided by the principle objectives stated in the Statement of Corporate Intent. If a specific conflict between stakeholder interests is identified, then an appropriate conflict resolution process will be adopted in order to resolve any concerns. The price-quality trade off is an 29

32 BACKGROUND AND OBJECTIVES example of this and the AMP sets out standards that the company believes are acceptable and affordable. In addition, customers sometimes have different reliability needs and they do not always agree on the same level of reliability or the price they are willing to pay for the service. Therefore, the level of services Top Energy aims for represents the average of our customers expectations. 30

33 BACKGROUND AND OBJECTIVES STAKEHOLDER EXPECTATIONS CURRENT DATA SOURCE MEASURES ASSET MANAGEMENT ACTIONS CUSTOMERS RETAILERS Fair Price Reliability Commerce Commission, Pricing Spreadsheets/ Budgets Billing System, DigSilent (Network Analysis Software) Regulatory Threshold Loss Factors OPEX and CAPEX expenditure is controlled & managed against the Annual Plan (which is consistent with the AMP) to ensure profitability and service levels are maintained within revenue constraints. Target levels are set and incorporated into daily planning and design activities to ensure minimisation of losses. SCADA, GIS, DigSilent Asset Utilisation Target levels are set and incorporated into planning and design activities to ensure maximum 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 CMS System (Call Management System) Customer Survey report Fault records (limited), SCADA and GIS Use of Systems Agreement and Industry Regulations Call Centre Stats Customer Survey Results Outage data transfers Tariff Changes Fiscally managed against Transpower s annual budget. Daily GXP demand/load management to ensure interconnection costs are well managed. DigSilent and load forecasting is used to ensure that just in time investment is made in new transmission infrastructure. The AMP targets are assessed for reasonableness through a comparison with peer group performance. Reliability is continually measured and reviewed against set targets. Work aimed at improving reliability is undertaken based on targeted condition based data and security standards. 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 of this. Top Energy owned call centre ensures customers are directed to one point of contact for quick and efficient service. Stakeholder expectations are incorporated into planning and decision making process. AMP ensures that compliance is achieved with standard industry protocols. AMP planning cycle ensures that timing for any tariff changes is coordinated between Top Energy and the retailers. 31

34 BACKGROUND AND OBJECTIVES STAKEHOLDER EXPECTATIONS CURRENT DATA SOURCE MEASURES ASSET MANAGEMENT ACTIONS BOARD TOP ENERGY CONSUMER TRUST Simple tariff Open Network Access Allocation of Losses Metering and Billing Safety Regular face to face meetings or Phone Conferences Industry Regulations and Transparency Monthly Loss Data and Network Analysis Software ICP Database, Retailer Records and Systems Industry Regulations and Standards Agreements from Retailers Published Plans & 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 & Statutory Compliance Capital Contribution Scheme Dividend Financial System Audited Financial Reporting Grow Asset Value Financial System, GIS Asset database Annually Disclosed Asset Valuation Current tariff structure has been developed in conjunction with retailers & reflects the business needs of all parties. Top Energy has a transparent pricing structure that is well explained. Target levels are set and incorporated into planning and design activities to ensure minimisation of losses. Top Energy relies on the retailers systems to reconcile revenue. The AMP drives health and safety requirements. 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 staff s 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 approved Annual Plan to ensure profitability and service levels are maintained. Timely investments are made to meet customer needs with long term value adding assets. 32

35 BACKGROUND AND OBJECTIVES STAKEHOLDER EXPECTATIONS CURRENT DATA SOURCE MEASURES ASSET MANAGEMENT ACTIONS Retain Ownership Survey Report Ownership Reviews as per SOI Overlay the desire of the shareholders for local ownership with a strong commitment for improving service levels and maintaining profitability. REGULATOR STAFF PUBLIC COUNCIL Table 11 Compliance with Regulations part 4A Legislation and Correspondence Monthly Reports & Forecasts Against Thresholds Health and Safety Safety Database Accident Report Statistics Job Security & satisfaction Training Safety Vegetation Control is Fair Land access rights upheld Resource Management Road Management Administration spreadsheet Administration Spreadsheet Industry Regulations and Standards Spreadsheet, GIS Reliability Database, SCADA, GIS Staff Turnover 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 set will be available when required. AMP reflects the skill set required which forms the input of the Training and Development Plan. The AMP drives health and safety requirements and only pre qualified contractors are allowed 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 Provides a clear definition of future work that should allow the business to comply with the relevant regulations. Legislation, GIS Consents for Work Acknowledges time frame for consent processes Procedures, GIS Consents for work Acknowledges time frame for consent processes Marine Crossings Procedures, GIS Consents for work Acknowledges time frame for consent processes and ongoing costs Relationship between Stakeholders and AM Plan 33

36 2.6.3 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 TEN s consumers and the Trust appoints the Top Energy Group to carry out the governance and management functions of the business. For instance, the Top Energy Board approves the annual SCI that outlines strategic direction, performance targets (both financial and quality), accounting policy and distribution service level targets. The Top Energy Board maintains governance over the Group through the development of strategy. The Board has input into performance targets delivered for signoff by the Trust and also approves the Annual Plan and all major capital expenditure. Figure 11 Top Energy Group structure The Top Energy Group is divided into four separate operating divisions. Although closely aligned through governance by the Top Energy Board, the four divisions operate independently, with separate operating budgets, and performance targets. TEN is one of the operating divisions of the Top Energy Group. It is managed on a daily basis by the Network Management Team under the direction of the General Manager Networks, who follows the direction outlined by the Board and Chief Executive Officer. The company has a set of delegated authorities for staff which have been approved by the Board. TEN is responsible for implementing the approved Annual Plan for the Networks Division. Any material variations from this plan in terms of scope or financial over-runs, together with all variations to projects with an agreed budget of $500k or greater, are presented to the Board for consideration at the first available monthly meeting. Variations to projects of less than $500k are generally discussed and agreed between the General Manager Networks and the Chief Executive Officer, although they may be raised for Board approval if it is believed to be material to the overall Annual Plan. With the exception of some specialist services, maintenance, faults and capital work, including major construction projects, on the network is undertaken by TECS, which is a separate division of the Top Energy Group and has around 95 staff comprising supervisors through to electricians and electricity lines staff. TECS operates from purpose-built depots in Kaitaia and Puketona. TEN manages work undertaken for it by TECS as if it were an external contractor. This arms length relationship is maintained by established Chinese walls around key operational and financial 34

37 BACKGROUND AND OBJECTIVES information between the divisions. Nevertheless, utilising contractors within one Top Energy brand promotes a close relationship with core staff. For field operations including maintenance and capital works, a Work Plan is produced annually by TEN. Specific work packs, including associated budgets, are issued to TECS prior to the commencement of work. For all work, estimated costs are comparatively benchmarked against current industry expectations to ensure cost efficiency of delivery is maintained. Field performance is monitored with weekly and monthly reports on the work progress and financial performance against budget. These reports are prepared as part of the General Manager Network s Board report. Any work outsourced to external contractors is under the supervision of the relevant TEN maintenance, planning or operations managers. 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. That is, in order to work on Top Energy s network, all staff are required to be assessed on their current competency on a 12 monthly basis. Staff must provide relevant training records, workplace audits, and operational evidence to prove their competency in undertaking certain tasks. The AHC holder is only allowed to perform the tasks to the specified level permitted after the assessment. Approval for issue of an AHC to any individual is by recommendation of the Network Operations Manager and consent of the General Manager Networks. The direct management of Top Energy s electrical assets and the associated planning is implemented by internal staff supported by external consultants as required. The structure of TEN s asset management team is outlined in the figure below. Figure 12 Top Energy Network Division - Section Structure 35

38 BACKGROUND AND OBJECTIVES The key responsibilities of the senior management staff within the TEN team are: Position Accountability General Manager Network Asset Maintenance Manager Planning Manager Programme Delivery Manager Manager Asset Information Systems Operations Manager To control the overall annually approved network budget. Approximately $25m. To control the overall annually approved maintenance and renewal budgets. Approximately $10M. To control the overall annually approved capital budgets. Approximately $18M. 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, monitor network performance. Business Analyst To monitor TEN s overall budget, network and financial performance. Engineers Delegated authority to manage projects to individual budgets. Table 12 Top Energy Network division levels of delegation Individual order approval levels are: CEO $1M General Manager Network $100k Section Managers $30k Engineers Nil present authority Table 13 Top Energy order approval levels TEN is the custodian of the network assets. It is responsible for ensuring that the utility assets are developed, maintained, renewed and operated on a long term sustainable basis to ensure that effective asset utilisation is achieved in providing services to the various stakeholders. Led by the General Manager Network, it is responsible for setting 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 executing the AMP within yearly renewal, maintenance, capital and operational expenditure budgets. The General Manager Network provides the following reports to the Board: Monthly reporting against the Annual Plan including operational, renewal, maintenance and capital expenditure; Justification for capital projects with an estimated cost greater than $500,000; Annual reporting of risk management; and Annual presentation and discussion on strategy and business planning, both short and longterm. In conjunction with internal design staff, external consultants are used during the design and planning phases. 36

39 BACKGROUND AND OBJECTIVES 2.7 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 feeder circuit breakers at Transpower GXPs, to be remotely operated from the central control room at Kaikohe substation. In addition it is possible to remotely operate switches and reclosers situated at strategic locations throughout the medium voltage distribution network. The SCADA system also records system and feeder half hour demand information, which is available via the Company s intranet website for further analysis and processing in separate systems Accounting/Financial Systems The Top Energy Group uses Microsoft Navision financial software for the management of expense, 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 spreadsheets 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 asset register and provides a spatial representation of assets, their relationships with one another, customers and vegetation all overlaid onto both Terralink base and 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: ODV application extracts data from the register of all assets and processes that data to produce the business s ODV. ICP Application - an application, which 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 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 37

40 BACKGROUND AND OBJECTIVES 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 is directly interfaced to the GIS system to provide 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 2000 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 all 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 database and standard MS Office products such as MS Access and Excel to manage the following: conventional maintenance management systems; tracking and forecasting models; long-term renewal, augmentation and maintenance planning by asset category; outage data and faults statistics; managing and reporting monthly performance data; and management of capital and maintenance projects Maintenance Management System Condition-based defect data and asset management schedules are currently managed within GIS and spreadsheets controlled by the asset management team. Options to invest in proprietary asset management software have been considered in the past and remain under review. 2.8 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. 38

41 BACKGROUND AND OBJECTIVES Figure 13 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 up to date. Following the identification of significant gaps in the asset records in 2006, the focus of the maintenance and GIS divisions over the last five years has been on gathering asset data from the field and loading it into the GIS asset register. The objective has been to improve the accuracy of the asset records and to centralise the storage of all asset data. The integrity checking process was introduced in May 2006 when 73 data integrity queries were run which collectively identified 202,106 individual data errors. These data integrity queries should be distinguished from data search queries, which are made by Top Energy staff in the course of their duties. The types of errors identified by data integrity queries include spelling mistakes, connectivity of equipment, conductor sizing, general asset information, asset attributes, capacity and condition information. Data gathering and remediation is prioritised by the areas that could potentially have more significant impacts to both operational and asset management decisions within the company. A number of the identified errors require site visits to resolve (i.e. duplicate pole and pillar numbers) and these are raised for inspection as part of the annual inspection maintenance cycle. Additionally, the GIS team is continuously reviewing the data to check for previously unidentified errors, errors created by specific users (operator data entry errors), reporting changes and changes of equipment brands. Data accuracy has increased significantly during the past two years. As of March 2010, the number of identified data errors within the GIS system is 947 or 0.026% of the total 3,635,177 records within the database. Data gathering and correction will continue with the intention of increasing data accuracy. 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 spreadsheet and returned to the GIS team for correction. GIS data is now considered to be highly accurate (>99.99%) 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 39

42 BACKGROUND AND OBJECTIVES 33kV zone substations 33kV lines 33kV switchgear Other technical equipment including SCADA 11kV cable and related equipment including switchgear 33kV cable and related equipment including switchgear 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 are known 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 and it is expected to be 2-3 years before all the missing data is collected. It is expected that the impact of any errors in within GIS will have a minimal impact on the reliability of the information presented in this AMP due to the following reasons: 1. The asset data is spatially accurate due to a systematic programme of GPS plotting of assets during the FYE The more critical 11kV and sub-transmission data has already been corrected. 3. Most 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. 5. The 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 recently developed a time-based asset inspection programme that covers all system assets. The frequency of inspection under this programme is determined by the expected rate of asset deterioration and a risk-based assessment of the consequences of an asset s failure. The inspection programme is undertaken by contract asset inspectors. It is complemented by a structured timebased non-invasive condition assessment programme that targets key assets such as power transformers as well as items that are prone to failure such as cable terminations. Defects identified during asset inspections and condition assessments are prioritised and recorded in an asset 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 and these are used as the basis for Board reporting on maintenance work undertaken and expenditure against the maintenance budget by the General Manager, Networks. 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. 40

43 2.8.3 Network Development Planning and Implementation BACKGROUND AND OBJECTIVES The Top Energy network development planning and implementation processes have undergone significant change over the last two years. During 2009, TEN completed a thorough review of the current levels of risk associated with 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 system model. This model, together with recorded SCADA information, future load growth predictions and asset defect, condition and attribute data, has been used to accurately determine the present utilisation of the Top Energy network assets and to identify areas of the present network unable to meet forecast load growth with an acceptable security of supply. Multiple scenarios were run to produce an optimized investment profile and network system, based upon the just-in-time need for capacity, followed by strengthening security of supply and ongoing performance improvements. This analysis, coupled with a forecast of future demand was used to prepare the Network Development Plan presented in section 5 of this AMP. This was independently reviewed by Sinclair Knight Merz (SKM), which reported that the extent of the proposed sub-transmission development is appropriate given the forecast load and the need to improve network reliability, which is poor in comparison to that of similar New Zealand EDBs. The Network Development Plan is reassessed on an annual basis after the load forecast is updated, taking into account the actual peak demand on the network, which normally occurs in August each year. The fundamental assumptions made in the formulation of the Network Development Plan are reviewed for their ongoing validity to ensure the plan efficiently and effectively addresses the immediate and foreseen security, reliability and capacity issues on the network. Actual network demand is checked against past projections to ensure that network growth is being realistically and accurately determined. Where necessary, demand projections are modified. 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. Similarly project cost estimates are reviewed as construction cost rates change, inflationary factors are taken into account and as the true impacts of resource consenting and easement costs become apparent. Capital projects are carried out by TECS with the exception of some specialist services, such as ground fault neutraliser (GFN) installation and commissioning work. Development projects are included in the Annual Plan, which is submitted to the Board as part of the annual budgeting process. Individual projects above $500k are then submitted in detail to the Board for individual approval prior to commencement. Once approved, all applicable design, consultancy and easement costs are captured as part of the overall project budgets. Project scopes are issued to TECS and field performance is monitored with monthly reports on work progress and actual financial performance against budget. Monthly financial project information is also available to authorised individuals within TEN and TECS and contracting services via the Navision finance software. 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 Customer Services 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 cross reference and verification of SAIDI and SAIFI statistics. Whiteboard also provides a list of faults with active or incomplete statuses, 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. This information, together with SCADA, is 41

44 BACKGROUND AND OBJECTIVES 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 impact for each fault event. For each fault that qualifies as a SAIDI, SAIFI or CAIDI event, 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. The systematic checks in the system ensure performance reporting is robust. Figure 14 Screenshot of the Faults Whiteboard. Network performance measurement and tracking is carried out as part of the responsibilities of the Network Operations Manager. Monthly fault statistics together with SAIDI, SAIFI and CAIDI performance are presented 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 AMP. 42

45 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 Subtransmission 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

46 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

47 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 15 Top Energy area of supply The majority of the district s land area is rural. The district has 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 populations. Top Energy provided services to 30,824 connection points as of 31 March Compared to New Zealand as a whole, the district is notable for a high proportion of people either on low incomes or unemployed or with lower rates of educational achievement. The affordability of services is a critical asset management issue to be considered by Top Energy Load characteristics and large users For the year ending 31 March 2010, the maximum demand was 70MW and the total energy delivered to customers was 358GWh. The majority of electrical load is residential, small commercial and agricultural. There are five large users as follows: Juken Nissho Mill at Kaitaia ( 10.6MVA); 45

48 APR MAY JUN JUL AUG SEP OCT NOV DEC JAN FEB MAR ASSET DESCRIPTION AFFCO Meat Works near Moerewa ( 2.4MVA); Immerys Tableware near Matauri Bay ( 1.1MVA); Mt Pokaka Timber Products Ltd ( 1.2MVA). Northern Regional Corrections Facility at Ngawha ( 0.6MVA); and All of Top Energy s major consumers, with the exception of Immery s Tableware, have dedicated service supplies from a local zone substation. Maintenance, renewal and replacement strategies for assets that affect the annual operations of major consumers are discussed and negotiated with the individual company. Often this involves maintenance activities scheduled for off-peak or non-operational periods. Top Energy also works closely with its major customers to manage their load requirements effectively and efficiently. Top Energy s distribution network is separated into two distinctly separate areas, the northern area including Kaitaia, Taipa and the far north peninsular and the more heavily loaded southern area including Rawene, Kaikohe, and the coastal towns of Kerikeri, Paihia and Russell. The northern area has a single point of injection, the Transpower grid exit point (GXP) close to Kaitaia which is supplied by a single 110kV circuit from Kaikohe. The existing firm capacity at the Kaitaia GXP is 20MVA with a current peak load of 24.8MVA. The total available transformer capacity at Kaitaia GXP is 40MVA There are two points of injection into the southern area, the Transpower GXP at Kaikohe and Ngawha Generation Ltd s 25MW geothermal power station at Ngawha, which is situated approximately 7km south east of Kaikohe. The existing firm capacity of the Kaikohe GXP, which is supplied by a double circuit 110kV line from Maungatapere (near Whangarei) is 20MVA with a current peak load of 43.6MVA. The total available transformer capacity at Kaikohe GXP is 59MVA. The monthly peak demands in the northern and southern areas for the year to 31 March 2010 are shown in Figure 16 below. TEN operates a 33kV subtransmisson network between the points of injection in its northern and southern areas and eleven zone substations, which in turn supply a total of 46 distribution feeders. The distribution feeders generally operate at 11kV, although approximately 20km of the Rangiahua feeder in the southern area now operates at 22kV. The loads on each individual feeder are shown in Figures 17 and 18 below. Low voltage (LV) distribution is at 415V 3-phase, 480/240V 2-phase, and 240V single phase. 70,000 60,000 50,000 40,000 30,000 20,000 10,000 NORTHERN MW SOUTHERN MW TE MAX DEMAND MW - Figure 16 Monthly peak MW 46

49 ASSET DESCRIPTION Figure 17 Southern 11kV Feeder Load Profiles Within the Southern area, the most highly loaded distribution feeders are those that feed Kerikeri and its surrounding area, namely the Riverview and Aerodrome Road feeders. This is the area that has experienced, and continues to experience, the highest levels of growth in the region. As detailed within section 5 of this plan, the establishment of a zone substation within Kerikeri township will enable the sectionalisation of these feeders to reduce overall loading constraints to within acceptable operational parameters. Figure 18 Northern 11kV Feeder Load Profiles Within the Northern area, the most highly-loaded distribution feeders are the dedicated feeders that feed the Juken Nissho Mill at Kaitaia, namely the Triboard 1 and Triboard 2 feeders. Juken Nissho has demonstrated an overall reduction in peak consumption over the last three years which has eased the criticality in progressing additional local supply upgrades. Whilst this situation continues, the plant 47

50 ASSET DESCRIPTION requirements will be closely monitored to identify the most appropriate time to install additional local supplies. Figure 19 Sub-transmission Feeder Load Profiles Whilst the 11kV feeders are subject to some localised load capacity constraints, the 33kV system is highly loaded at peak periods and this has created a number of constraints that adversely affect the security and capacity of supply to the region. The key weaknesses are: single circuit supplies to Omanaia, Pukenui and Taipa, and Kaikohe (110kV) zone substations; a single circuit 33kV line to the Ngawha geothermal power station presently running at 95% capacity with no alternate supply; capacity constraint issues on the 33kV lines to Waipapa substation. This is a voltage constraint in that the ability to maintain an acceptable voltage level in the Kerikeri area is now marginal if one of the two subtransmission lines supplying Waipapa zone substation is lost at times of peak load; protection constraints that require all 33kV lines and substations to operate in a radial configuration. This will result in an unavoidable loss of supply to some customers if any subtransmission element should fail; a protection constraint requiring an intertrip of the two subtransmission circuits to which the Ngawha geothermal power station is connected in the event of a fault on either circuit. This constraint creates a potential for a major power outage affecting much of the southern area as a result of a single subtransmission fault; and transformer capacity constraints or a lack of redundancy meaning that N-1 capacity either does not exist or will be lost during the planning period at Omanaia, Kawakawa, Waipapa, Taipa and Pukenui. This means that supply cannot be fully restored, even after switching, following a fault until the fault is repaired. To alleviate these security and capacity issues a comprehensive re-configuration of the 33kV network is planned and that is discussed in detail in section 5 of this plan Sub-transmission system Figure 16 is a geographic diagram of Top Energy s 33kV sub-transmission network and includes some of Transpower s transmission system. Currently, the two GXP s are non-inter-connectable at sub- 48

51 ASSET DESCRIPTION transmission (33kV) level, however it is planned within the planning period of this AMP to interconnect the 33kV system at Kaeo, between Waipapa and Taipa. Further details of this are covered within section 5 of this plan. Although the northern and southern networks can be connected at 11kV level, it is not possible under normal operational conditions due to load and voltage differentials between the two networks. The figure below shows present Top Energy 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 standardised on an 11.5/23MVA design for many of its larger load substations to allow the relocation of transformers in case of an emergency should a single unit fail. However, the actual tap changer capacity in some of the zone transformers limits ability to maintain acceptable voltage levels. To allow transformer maintenance and to provide back up to locations where only a single 33/11kV transformer is installed, Top Energy has commissioned a 7.5 MVA mobile transformer unit. 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 Northern GXP T MVA ONAN (Has no pumps or fans) T MVA ONAN (Has no pumps or fans) Taipa T1 5/6.25 MVA ONAN/OFAF (Has no pumps but fans are fitted 6.25 Pukenui T1 5/6.25 MVA ONAN/OFAF (Has no pumps or fans) 5.00 NPL T1 11.5/23 MVA ONAN/OFAF (Has both pumps and fans) T2 11.5/23 MVA ONAN/OFAF (Has both pumps and fans) Table 14 Present Zone Substation Transformers 49

52 ASSET DESCRIPTION The table below 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 Top Energy network supply only, i.e. the Northern GXP is not N-1 as there is only one incoming 110kV circuit. As can be seen from the table, six of the ten zone substations are outside of the N-1 threshold. In addition, all of the substations operate in open bus position due to transformer protection constraints and therefore do not currently meet the Top Energy security of supply standard. SUBSTATION UNIT PRESENT RATING (MVA) SUBSTATION PRESENT CAPACITY (MVA) Southern GXP Firm (N-1) 11kV feeder Switched Capacity Year Substation N- 1 Exceeded Kaikohe T >2020 T Kawakawa T T Moerewa T >2020 MOB 7.50 Waipapa T T Omanaia T Current Haruru T T Mt Pokaka T >2020 Northern GXP Firm(N-1) 11kV feeder Switched Capacity Year Substation N- 1 Exceeded Okahu T >2020 T Taipa T Current Pukenui T Current NPL T >2020 T Table 15 Present Zone Substation Transfer/Switching Capabilities Distribution system The Top Energy distribution system consists of 46 predominantly overhead line rural feeders, which supply 5,933 transformers as at 31 March Figure 20 through Figure 29 show the distribution system for each of the Company s zone substations. The percentages of underground to overhead line are as follows: 50

53 ASSET DESCRIPTION Sub-transmission - Overhead 99.25%, Underground 0.75% Distribution - Overhead 95.7%, Underground 4.3% Low Voltage - Overhead 42.6%, Underground 57.4% Due to the extensively rural nature of the network, the majority of substations are overhead in construction, feeding local LV or sub-service customers. This results in limited inter-connectablility between substations and transformers at LV level except in the heavily populated areas of Kaikohe, Kaitaia, Kerikeri, Russell and Paihia. For approximately 30 years, Top Energy standards have required new LV developments and subdivisions to be underground systems, which have resulted in a high percentage of underground distribution at LV level and the 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. 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. Transformer size kva Number Pole Mounts Number of Pad Mounts Under

54 ASSET DESCRIPTION Table 16 Distribution Transformer Population Figure 20 Geographic diagram of the Pukenui zone substation Figure 21 Geographic diagram of the Taipa zone substation 52

55 ASSET DESCRIPTION Figure 22 Geographic diagram of the NPL zone substation Figure 23 Geographic diagram of the 33kV Okahu Road zone substation 53

56 ASSET DESCRIPTION Figure 24 Geographic diagram of the Kaikohe zone substation Figure 25 Geographic diagram of the Waipapa zone substation 54

57 ASSET DESCRIPTION Figure 26 Geographic diagram of the Haruru zone substation Figure 27 Geographic diagram of the Kawakawa zone substation 55

58 ASSET DESCRIPTION Figure 28 Geographic diagram of the Omanaia zone substation Figure 29 Geographic diagram of the Moerewa zone substation 56

59 ASSET DESCRIPTION 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. The 2007 review of Section 62 of the Electricity Act 1992 revised the Act, so that the obligation to supply line function services to all customers supplied as at 1 April 1993 must continue to be met by using either lines, or alternative generation after 1 April The Electricity Networks Association (ENA) created a working party to review the implications of the Act change, particularly within distribution companies that comprise of a large rural network component. To assist this review, in April 2009, Top Energy engaged Intergraph to create a trace within the GIS system to identify uneconomic lines using data in relation to the Ministry of Economic Development (MED s) 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 collated results revealed that 32.38% of Top Energy lines are in fact uneconomic but these uneconomic lines feed only 7.97% of Top Energy s customer base. The following table details the results calculated for each individual zone substations and applies the criteria of less than 20kVA per ICP and less than 3 ICPs per km of line. ZONE SUB UNECNMC LENGTH TOTAL LENGTH % LENGTH UNECNMC CUSTOMERS SUPPLIED TOTAL CUSTOMERS SUPPLIED % CUSTOMERS UNECNMC Kaikohe Kawakawa Moerewa Waipapa Omanaia Haruru Okahu Rd Taipa Pukenui NPL Total Table 17 Uneconomic lines 57

60 ASSET DESCRIPTION Figure 30 Map showing uneconomic lines 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. These devices are used to detect and isolate a fault as quickly as possible to ensure that damage is minimised 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 either its own VHF network or the leased UHF broadband network 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, Okahu Road with a standby plant at Waipapa substation. The load management plants are effectively used to control demand by allowing the organisation to control a range of load types. This allows the organisation to manage its peak charges and to potentially defer capital investment on the network. 58

61 ASSET DESCRIPTION The large number of receivers installed in the field at the point where the controllable load is connected, are not owned by Top Energy. They are owned by energy retailers. 3.2 Asset Details by Category An audited ODV was due for publishing in 2007; however, this was postponed as the Commerce Commission was then in the process of consultation with Electricity Distribution Businesses (EDBs) on the valuations of their distribution system fixed assets. The Commission is now requiring EDBs to value their system fixed assets for regulatory purposes using an indexed roll forward of the 2004 ODV valuations, which means that an updated ODV is not needed. There is however, the opportunity for Distribution Lines Companies who are following a Regulatory Default Price Path to review and update their 2004 ODV valuation in 2011 as part of the Regulatory Input Methodologies. The overall level and accuracy of asset data has improved significantly since 2004 and it is envisaged that the result will be improved accuracy of the next valuation. The disclosed asset value at 31st March 2010 was $ million. A summary by asset category per the last audited ODV in 2004 is shown in the table overleaf. Table 18 ODV summary as at Overhead conductors Overhead conductors are split into three categories; sub-transmission (33kV), distribution (22kV & 11kV) and low voltage (400V). 59

62 Length (metres) ASSET DESCRIPTION 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. Due to TEN s close proximity to the sea at certain locations, a high content of salt is causing corrosion of ACSR conductor. Because of this TEN has reviewed the use of ACSR conductor and is trialling AAAC (All Aluminium Alloy Conductor) Sub-transmission The figure below shows the age profile of sub-transmission overhead conductors. Sub-transmission Overhead Line Conductor Total Age(years) Figure 31 Age profile of sub-transmission overhead conductors There is a total of 269 km circuit length of sub-transmission overhead conductor. In general, the condition of sub-transmission overhead conductor is acceptable. Significant replacement of key circuits is required however, within the planning period as a consequence of the Network Development Plan. 60

63 Length(metres) Length (metres) ASSET DESCRIPTION Distribution The figure below shows the age profile of distribution overhead conductors Distribution Overhead Line Conductor Total Age(years) Figure 32 Age profile of distribution overhead conductors There is a total of 2,753 km circuit length of distribution overhead conductor. The condition of this conductor varies considerably. Main feeder condition is generally acceptable, however older #8 conductor used for SWER lines is reaching end of life. In some cases upgrade or replacement will be required, while in other cases alternative load control initiatives and technologies are being investigated (eg. peaking batteries for SWER systems) to address capacity issues without requiring conductor replacement Low Voltage The figure below shows the age profile of low voltage overhead conductors Low Voltage Overhead Line Conductor Total Age(years) Figure 33 Age profile of low voltage overhead conductors There is a total of 284 km circuit length of low voltage overhead conductor, which is of average condition. The main risk to the condition of LV conductor is clashing caused by vegetation. This is being targeted as a key initiative through a three year $9m vegetation strategy, described in Section 6. Replacement options, which will be considered on a case by case basis, include the use of LV ABC or undergrounding where appropriate. 61

64 Count of poles ASSET DESCRIPTION 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 sub transmission and distribution network. The four types of poles and structures used are: hardwood, softwood, steel and concrete. Top Energy was an early adopter of concrete poles and hence the population of wooden poles on the network is not as significant as other similar sized networks. The pole assets for each voltage level are considered separately, a pole s voltage level is determined by the highest voltage supported by it. It is observed that: the sub-transmission network has been built sporadically over the last 60 years; since the 1960 s the distribution poles have been mainly concrete, and they continue to be installed in significant numbers. Ten percent (10%) private ownership of medium and low voltage overhead lines has been allowed in company valuations and the data capture program is facilitating the identification of poles that are in fact service line poles and belong to customers. This more detailed information will lead to the development of a strategy for ensuring private lines are maintained to a level that does not hinder the provision of service to other customers Sub-transmission The figure below shows the age profile of sub-transmission poles Sub-transmission Line Poles 100 Total Age (years) Figure 34 Age profile of sub-transmission poles There are a total of 2,881 sub-transmission poles. Annual inspections of sub-transmission poles are showing that the majority of the poles are in good condition; however a significant number will be replaced as part of the Network Development Plan proposed within this AMP. It is anticipated that the average age of the sub-transmission pole assets will be reduced to less than 25 years as a result of the projects proposed within this AMP. 62

65 Count of poles Count of poles ASSET DESCRIPTION Distribution The figure below shows the age profile of distribution poles Distribution Line Poles Total Age (years) Figure 35 Age profile of distribution poles There are a total of 31,080 distribution poles. Although Top Energy s distribution poles are deemed to be in generally good condition, some work is still required on aging SWER lines. The majority of the higher risk wooden poles lie within this category and it is planned that the wooden pole population of approximately 4,000 poles will be routinely replaced for concrete structures over the next 20 years Low Voltage The figure below shows the age profile of low voltage poles. 200 Low Voltage Line Poles Total 0 Age (years) Figure 36 Age profile of low voltage poles There are a total of 1,461 low voltage poles. TEN has built very little LV overhead since 1986 and this is reflected in the graph with only 222 poles less than 20 years old. These assets will continue to be inspected for condition on a regular basis and programmed for replacement as necessary 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 63

66 Length(metres) Length(metres) ASSET DESCRIPTION Energy has 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 0.5 km 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 Distribution Voltage Underground Cables Total 0 Age(years) Figure 37 Age profile of distribution underground cables There is a total of 162 km of distribution underground cables, which are generally in good condition. Top Energy experiences on average one underground high voltage fault every 3 to 5 years, with the majority of these being joints or third party damage. This is reflective of both the limited amount and young age of Top Energy s underground distribution system. Ongoing 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 Low Voltage Underground Cable Age(years) Year of Manufacture Total Figure 38 Age profile of low voltage cables There is a total of 1,112 km of low voltage underground cables which are considered of average condition. Ongoing monitoring will continue to identify any developing fault trends. 64

67 Count of distribution transformers 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, 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 150 mm 2, 11kV,copper cable livened in This will provide a medium term solution to address the load issues in the area. A third cable is planned for installation in 2015 at 22kV in preparation for the Russell 22kV feeder upgrade project beginning in Streetlight Cables Street light cable (222km, economic life as per ODV handbook is 45 years, average age 20.8 years resulting in a remaining life of 54%) has not been included in the above. A strategy for dealing with street lighting in the long term will be developed in conjunction with the light owners before maintenance becomes a material issue. Streetlight cabling however has been generally assessed as having ample life remaining and not requiring significant maintenance during the next 10 years. ASSET DESCRIPTION Distribution Transformer and SWER Transformers The age profiles of Top Energy s in-service distribution and SWER isolating transformers are depicted in the figures below. 400 Distribution Transformers Total 0 Age (years) Figure 39 Age profile of distribution transformers (all voltages) There are a total of 5,933 distribution transformers of various voltages. In general, Top Energy s transformer population is of average age and condition. Top Energy considers the most appropriate strategy for the management of transformers to be one of run to failure, with the exception of transformers that are deemed upon inspection to pose a risk to persons, safety, environment or property. Transformers are inspected on a biannual basis and those which are identified as requiring replacement are programmed. 65

68 Count of reclosers Count of SWER isolating transformers ASSET DESCRIPTION 10 SWER Isolating Transformers Total 0 Age(years) Figure 40 Age profile of SWER isolating transformers There are a total of 75 SWER isolating transformers. SWER Transformers are managed on an individual basis, dependant on the connected system and future forecast load requirements. As an alternative to upgrade, alternative load control initiatives and technologies, such as peaking batteries, are currently being investigated Reclosers The figure below shows the age profile of Reclosers on Top Energy s Network. 40 Reclosers Distribution Sub-transmission Age(years) Figure 41 Age profile of reclosers There are a total of 6 sub-transmission and 111 distribution voltage reclosers on Top Energy s network, 36 of which (included all the sub-transmission units) were installed as part the network automation project that commenced in The general condition of reclosers is considered good. Annual condition inspection is carried out to identify replacement requirements Voltage Regulators The figure below shows the age profile of the voltage regulators on Top Energy s network. 66

69 Count of Ring Main Units Count of regulators ASSET DESCRIPTION Voltage Regulators Age(years) Total Figure 42 Age profile of regulators There are a total of 21 voltage regulators on Top Energy s Network. These are all less than ten years old and in good condition. Annual condition inspection is carried out to identify replacement requirements Ring Main Units (RMU) The figure below shows the age profile of RMUs on Top Energy s Network Distribution Ring Main Units Total 0 Age(years) Figure 43 Age profile of ring main units There are a total of 468 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. As these are now no longer being manufactured, discussions are underway with the manufacturer to ensure availability of spares whilst the population remains operational. Alternative supply options for new RMU s are being considered. 67

70 Count of Capacitors Count of sectionalisers ASSET DESCRIPTION Sectionalisers The figure below shows the age profile of sectionalisers on Top Energy s Network Sectionalisers Total Age(years) a. Figure 44 Age profile of sectionalisers There are a total of 260 sectionalisers on Top Energy s Network. Sectionalisers are a relatively new asset on the network and replacement of the three remaining older units is planned as part of the routine maintenance schedule Capacitors The figure below shows the age profile of capacitors on Top Energy s Network Capacitors 2 Total Age(years) Figure 45 Age profile of capacitors There are a total of 21 capacitors on Top Energy s Network. The capacitor units are all of average to fair condition. Annual condition inspection is carried out to identify replacement requirements. 68

71 ASSET DESCRIPTION Zone Substation Equipment Power Transformers & Tap-changers The table below shows the details of power transformers located at Top Energy s Zone Substations. The same has been pictorially shown in the table below. PRESENT SUBSTATION UNIT DESIGN RATING MVA PRESENT RATING MVA AGE 1 EXPECTED LIFE (Y) Southern 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/ Haruru T2 11.5/ Mt Pokaka T1 3/ 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 January 2011 Table 19 Power transformers installed at zone substations 69

72 Count of transformers ASSET DESCRIPTION Power Transformers Total Age (years) Figure 46 Age profile of power transformers As per the ODV Handbook, the budgeted age for transformer replacement is 45 years. However clause A.40 of the ODV Handbook provides for this life to be extended to up to 60 years where appropriate maintenance practices are in place. The actual age at which a power transformer will be replaced will depend on its condition, loading, history and design and Top Energy expects that most of its transformers will last well beyond the nominal 45 years. Top Energy principally follows the loading recommendations for normal transformer aging as per IEC , with secondary reference to IEEEC The recommendations are applied by carrying out spreadsheet calculations on an annual basis should the load venture into the accelerated aging region of IEC354, at any time in the previous year. The use of real time age modelling, either with a computer or with transducers having load cycle aging algorithms in them is not currently employed and is not required due to the general low to-moderate level of loading. Furan oil analysis is used as a non-invasive indication of degree of polymerisation (DP) of the transformer insulation. The remaining life of a transformer is assessed on the basis of actual DP tests, should a major overhaul involving de-tanking at a transformer workshop be required. The DP at start of 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 have been ascertained over when paper samples were taken and analysed. DP s are in two groups: most are between 695 and 1,300, i.e. plenty of life left in the cellulose, whereas the three single phase Metropolitan Vickers units at Omanaia, which are now 57 years old, are closer to end of life at and will be replaced by the existing Taipa unit in

73 Count of 33kV circuit breakers ASSET DESCRIPTION Circuit breakers a) Sub-transmission circuit breakers The figure below shows the quantities and age profile of Top Energy s Sub-transmission circuit breakers Sub Transmission Circuit Breakers 2 Total Age(years) Figure 47 Age profile of sub-transmission circuit breakers Top Energy has a relatively small number of such circuit breakers and as a result, there is a concentration of types. There are 12 x English Electric OKW3 minimum oil 33kV CBs described in the and age brackets. Minimum oil CBs are a circuit breaker class that are noted internationally as having major risk of failure if the maintenance programme is not rigorously followed. The first instance requiring replacement occurred in 2005 and a replacement regime has subsequently been planned. 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. One spare breaker is not installed. Until replacement occurs, Top Energy will apply a strict maintenance regime on a 12 monthly cycle. In addition there are the following 33kV breakers in service: 4 x modern outdoor vacuum interrupter units dated 2002 at NPL and Okahu Substations; 3 x RVE oil interrupter units one at each of Omanaia, Pukenui and Taipa Substations. 2 x modern outdoor Nova reclosers units dated 2008 are installed at Haruru. 71

74 Count of 11kV circuit breakers ASSET DESCRIPTION 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 Distribution Voltage Circuit Breakers 10 Total Age(years) Figure 48: Age profile of distribution voltage circuit breakers The condition of these items is considered sound with thorough testing and condition based maintenance in place, as outlined below. 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 table 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 Table 20 Type and location of 11kV circuit breakers 72

75 Zone Substation Structures Top Energy s outdoor structures, like overhead lines have a long life span. Their condition can be monitored visually and with the use of thermal imaging. Because of the critical nature of the air insulated switch items within substations, they are individually checked for correct operation every two years and maintained if necessary Zone Substation DC Systems The documentation of the age of batteries and charger systems is complete and summarised in the figure below. Top Energy inspects and tests the battery banks monthly and replaces the whole bank at the end of its economic life. ASSET DESCRIPTION Figure 49 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 to a type capable of data logging commenced in The key business driver for this is the feeder load and fault data that will be obtained, allowing for better network analysis and in turn service delivery. It will also assist in tariff and loss calculations and the allocation of costs. In addition, having a modern protection scheme in place will assist in minimising mal-operation risks, which can result either in unnecessary outages or failure to trip. Compared to the existing relays, the new relays will have many additional functional benefits that allow for better discrimination with other devices. Sub-transmission circuits generally do not have directional protection, but as part of the proposed Network Development Plan, a move towards directional protection is proposed to allow the meshing of the upgraded sub-transmission system and provide outage free fault clearance where N-1 security is required. 73

76 Count of pillars ASSET DESCRIPTION Zone Substation Grounds and Buildings Top Energy s Substation Buildings are listed in the table 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 Table 21 Age profile of substation buildings The buildings are all considered to be in fair condition although certain maintenance on zone substation buildings (i.e. roof repairs) may be necessary within the next 5 years. Building inspections and maintenance programmes ensure the utility of buildings 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 11,530 installed on the network. Service Pillars Age(years) Total Figure 50 Age profile of customer service pillars 74

77 SCADA and Communications Top Energy s 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. Upgrade of the remaining substations is to follow in subsequent years. 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 substation 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. ASSET DESCRIPTION The figure below shows the location of repeater sites. Figure 51 Repeater tower sites 75

78 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. 3.3 Justification for Assets TEN s network assets are used to accept electricity from Transpower s grid exit points at Kaitaia and Kaikohe and from the Ngawha geothermal generation plant and to distribute the electricity to consumers in the Far North, with the quality and reliability they demand. While these assets have historically met consumer requirements, the demand for electricity and consumers expectations in respect of quality and reliability are now exceeding the capacity of the existing asset base, as noted in Section 2.4 Hence Top Energy is implementing a new Network Development Plan, described in Section 5, which will put in place an augmented sub-transmission infrastructure 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 network is substantially radial in nature and includes 33kV sub-transmission lines, 22/11kV distribution lines and 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 mainly 3wire, 2wire 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 2, 3 and 4 wire lines which are largely underground. 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. Appendix B shows typical zone substation configurations in the Top Energy network. Top Energy believes the asset base is no longer adequate to provide acceptable supply reliability to consumers and comply with statutory requirements in relation to delivery voltages. Distribution feeders operate at 11kV and are long for this voltage. The identification of surplus or over-capacity assets was considered in the optimisation process undertaken for ODV purposes (last undertaken in 2004). 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 could mean that some assets that were optimised for capacity reasons at that time would no longer be optimised if a new valuation was undertaken Grid Exit Points (GXP) The two GXPs, Kaikohe and Kaitaia are approximately 80km apart with a range of uninhabited hills in between. The southern and northern area distribution networks are currently interconnected at 11kV at only one remote location and also, could not be practically interconnected using 33kV subtransmission lines. Both the GXPs have dual 110/33kV transformers to allow the transformers to be maintained during off peak periods without loss of supply. The GXPs are supplied from Mangatapere using a double circuit 110kV line up to the Kaikohe GXP. The Kaitaia GXP is, in turn, supplied using a single circuit 110kV line from the Transpower Kaikohe 110kV Substation. As the Kaitaia GXP 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 Ltd also provides 25MW injection into the Top Energy network at 33kV. The Ngawha Power Station is situated approximately 7km from the Kaikohe GXP. The Power Station is connected to TEN using a single circuit 33kV line No optimisation of the GXPs is possible. ASSET DESCRIPTION 76

79 3.3.2 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 predicted 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 security requirement set out in the plan requires at least both the 33kV lines and precludes a reduction in the conductor size. 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 line from Kaikohe GXP. Omanaia Substation is supplied using a single 33kV line from Kaikohe GXP. This substation can not 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 limited backup available for all substations from adjacent substations via the distribution network but that backup is severely limited due to voltage drop on the distribution feeders under contingent operations. All zone substation transformers are of adequate size to supply present load under normal operating condition and most (but not all) substations meet N-1 security criteria as far as transformer size is concerned given the forecast load increase for the planning period.. The configuration and the size of equipment such as transformers, circuit breakers etc within each substation has been considered with the basic requirement of providing the levels of security set out in this AMP. 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. 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. There are three areas of Zone Substation optimisation possible in the Top Energy Network. Firstly, some of the installed 33/11kV transformers are dual rated 11.5/23 MVA units. Where appropriate, based on the 10 year load forecasts, transformers could be optimised to reflect a smaller 5/10 MVA unit for valuation purposes. At Omanaia zone substation, there are three single phase transformer units with separate voltage regulators. For the ODV valuation, this combination was optimised to a single three phase unit with an internal on load tap changer (OLTC). 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 could be optimised out. ASSET DESCRIPTION 77

80 L o ad in M V A ASSET DESCRIPTION Finally, the zone substations land and building values could be adjusted to reflect an appropriate size. During the 2004 ODV Single bank substation sites were optimised to 2000m 2 and double bank substations to 3000m Distribution network Top Energy uses conductors classified by the Commission s ODV Handbook as medium or light. Factors such as current rating, losses and voltage drop are considered to decide whether these should be optimised to smaller size conductors. Although from an engineering point of view it would be possible to consider a wide variety of conductor sizes, for valuation purposes there is only one option. That is to reduce medium conductors to light. Top Energy s medium conductor (Bee 130mm 2 ) and its light conductor (Ferret 40mm 2 ) were used to model the options for optimisation. 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. To achieve the security criteria set out in this AMP, the feeder s 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 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. T ransm ision Capacity Volt Drop L en g th in km B ee F erret Figure 52 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 at least medium conductor. Only two feeders were still subject to possible optimisation; Tau Block and Pokapu. Pokapu cannot sensibly be used to back up the AFFCo feeder, but has less than 1km of Bee conductor so was not considered material. Tau Block is used to back up the remaining two feeders out of Moerewa 78

81 ASSET DESCRIPTION substation in order to meet the reliability requirements of the industrial customer adjacent to the substation In accordance with the provisions of the ODV Handbook SWER lines were valued at the same as two wire lines and the isolating transformers given zero value. Hence 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 For optimisation of distribution transformers, Top Energy calculated the percent utilisation factor based on the network peak demand less the demand at high voltage level divided by the total connected distribution transformer capacity. Any excess distribution transformer capacity would need to be optimised down to achieve utilisation of no less than 30% as per the requirement set out in the ODV Handbook. This is one area where, under existing rules, some further optimisation may be necessary in the event of a new ODV valuation. However there is little Top Energy can do to alleviate this situation, given the need to supply sparsely populated rural areas and the fact that the minimum size distribution transformer now available exceeds by a substantial margin the peak demand of most residential customers Low voltage network TEN provides no back up for LV circuits. Circuits are either two, three or four wire, using medium conductor (the smallest size in the ODV Handbook) which precludes optimisation of conductor size. 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 volt drop rather than capacity is the normal constraint. Increasing the conductor size is not the optimal solution in general. New construction consists entirely of underground cables. In urban areas, this is a requirement of The Far North District Council 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 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 seventeen 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 not material. 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) 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. It has the right to operate the Transpower 33kV breakers directly. 79

82 ASSET DESCRIPTION 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 achieve a significant improvement in reliability and to meet the security criteria set out in the AMP. With only 44 feeders and approximately 3000km of overhead HV line, the ability to reduce the time taken 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. 80

83 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 Technical Orientated Service Levels 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 93 81

84 LEVEL OF SERVICE 4 Level of Service 4.1 Introduction Top Energy distributed electricity to an average of more than 30,000 consumers during via approximately 4,100km of lines and cables of which 81% is overhead. This gives an average consumer density of 7.3 consumers per km. This groups Top Energy with companies such as MainPower, Eastland Network and Alpine Energy, which also have significant rural areas of supply. The last three years has seen a steady decline in Top Energy s network performance to the extent that it is now one of the worst performing companies in New Zealand in terms of supply reliability. During , on average, each customer experienced four outages and almost eight hours without electricity. Whilst this performance was significant improvement on the previous year, it 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 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 grid exit points (GXPs) from Transpower, when a more strategically located rural network of similar size would typically have many more. Further, the GXPs 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 the areas of 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 over $200M during the next decade in what will be the single largest expansion in the history of the electricity network. The work will expand and strengthen the 33kV sub-transmission system in order to increase the number of bulk supply points at which power is injected into the older distribution network. Key projects that are identified within this plan include seven new zone substations and over 200km of new 33kV line construction. The result of this expansion will be a significantly more secure and reliable network to support the future economic growth of the Far North. Sub-transmission and 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 to 463 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 new technologies and strategies that offer the best mix of performance gains compared to the cost of implementation. The work planned over the next decade will also have a significant impact on the human resource requirement at Top Energy and will create new job opportunities in the Top Energy area. An initial 82

85 LEVEL OF SERVICE recruitment campaign for planners, project managers, electrical lines engineers and other staff was launched in January Further recruitment will take place to support the delivery of the programmes described in this AMP and around 20 new permanent positions may arise from the investment in the electricity network operation over the planning period. In order to inform, educate and seek feedback from customers on what is an appropriate level of service, Top Energy performs regular customer research. By assessing the Company s performance and comparing it with specific target levels, the Company 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 this customer research have been incorporated in the strategies discussed in this AMP and guided development of the target levels of service proposed within this chapter. Top Energy s corporate strategic direction is reflected in its Statement of Corporate Intent (SCI), the objectives of which state the intention to: Operate a successful and responsible business, and Maximise the long term benefit to shareholders. In-house discussion on these objectives and the customer consultation undertaken emphasise the importance of: Business and regional economic development; Service; Quality; Financial; Skills training and development; Environment; Improvement; and Employee health and safety In terms of strategic intent, the service level measures adopted for this AMP align with standard regulatory performance measures and customer expectations. However, there are areas of the service level measures relating to a number of the above criteria that are currently under evaluation with a view to improving their relevance to achieving the desired strategic outcomes. The result of this process will be incorporated into the next version of this plan in Customer Orientated Service Levels Adopted customer service level 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 and, in the view of Top Energy, effectively measure the extent to which TEN is able to achieve its objective of supplying a reliable electricity supply to its customers. This aligns with the view of the Commerce Commission which, following a process on intensive public consultation at a national level, also uses these indicators as the basis for setting a quality threshold which it uses 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 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 83

86 LEVEL OF SERVICE measurement year as a result of faults and planned outages on the Top Energy 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. 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 on its measured performance. The normalisation process will have the following effect. 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. 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 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 TECS 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. Top Energy s normalised SAIDI and SAIFI targets for the planning period are shown in the figure below. SERVICE LEVEL TARGET SAIDI (Excludes Transpower) Note: the Regulatory Benchmark applied over is 464. For the new Benchmark is Table 22 Customer service levels YE 2011 TARGET YE 2012 TARGET YE TARGET SAIFI (Excludes Transpower) The targets in the table above are averages. The exact levels of service experienced by an individual consumer will depend on the consumer s location on the network. Top Energy must meet regulatory compliance thresholds set by the Commerce Commission for both SAIDI and SAIFI. The targets in Table 22 above reflect a much higher level of reliability than the compliance thresholds set by the Commission, which have been influenced by the very poor levels of reliability experienced in the years ending 31 March 2008 and 31 March These improved reliability targets are possible due to the expected impact of Top Energy s vegetation management 84

87 LEVEL OF SERVICE programme and also the installation of remote controlled switches and reclosers on the network during the financial year to 31 March As shown in Table 22, Top Energy is targeting even further improvements in reliability over the remainder of the planning period, to 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. While the performances shown exclude the impact of Transpower outages, they have not been normalised for major event days and therefore cannot be directly compared with the target reliability levels shown in Table SAIDI SAIDI THRESHOLD Figure Historical and forecasted YE 2010 SAIDI performance SAIFI SAIFI THRESHOLD Figure 54 Historical with forecasted YE 2010 SAIFI performance 85

88 4.2.3 Strategies to improve the customer level of service LEVEL OF SERVICE The poor 2008 SAIDI performance prompted a thorough review of fault causes and maintenance practices. The actual causes of faults in 2008 are shown in Table 23 below. Following this analysis Top Energy has developed strategies to mitigate the predominant causes of faults and, as shown in the table, by 2015 these strategies are expected to have a significant impact. FAULT ACTUAL 2008 % TARGET 2015 % Vegetation Related 52% 5% Lightning Related 21% 2.5% Equipment Failure 9% 5% Animals 4% 2.5% Planned 9% 50% 3rd Party 4% 15% Transpower 1% 20% Table 23 Breakdown of line faults Internal targets have been set to: Reduce Vegetation Faults to < 30 Faults per year (Currently 54) Reduce Lightning Faults to < 5 per year (Currently 7) Reduce Equipment Failure Faults to < 25 (Currently 96) Monitor and Target performance in line with the Identified Industry Peer Group of Companies The 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. Top Energy is currently implementing a programme that will spend approximately $3m per annum on vegetation management over a three year period. This is expected to reduce the vegetation problem to a manageable level. After the initial three year effort, vegetation control will transition to a maintenance mode, and much of the trimming costs will be paid by tree owners. the use of automatic switching devices and line fault indicators, (i.e. distribution automation); the use of remote control of switches; the use of live line work; and extensive data capture is being undertaken to obtain a better understanding of the asset so that the Company can improve the effectiveness of its condition based replacement programme. A key factor in determining 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 86

89 LEVEL OF SERVICE 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 on response times. Although the use of automatic and remote control devices can assist in the isolation of faulty areas and restoration of supply, safety procedures usually require a physical patrol of lines before restoration. 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 of 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 resulting from the high network loading and the rural nature of the network. 12.0% Historic Loss Ratio 10.0% 8.0% 6.0% Loss Ratio 4.0% 2.0% 0.0% (Source: Commerce Commission Disclosure Information / Actual 2010) Figure 55 Loss Ratios of Top Energy since

90 LEVEL OF SERVICE SERVICE LEVEL TARGET YE 2011 TARGET YE 2012 TARGET YE TARGET Loss Ratio 8% 8% 8% - 6.5% Table 24 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 and not network companies are responsible for the cost of energy 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. Similarly another area that can cause significant losses is related to metering errors and electricity theft. Retailers are primarily responsible for meters and the customer s contractual relationship; however, Top Energy is working proactively with both specialist external consultants and retailers to manage these issues. Top Energy intends to conduct investigation audits for all customer categories on the network with the intention of reducing non-technical losses on the Network. Historically, Top Energy has experienced a high loss ratio, running at approximately 10% from 1996 to In recent years the loss ratio has reduced to its current levels of 7.7% in , 8.0% in , 8.8% in and 8.6% YTD in Top Energy is targeting a value of 6.5% by 2020 which is both reflective of the average for rural networks in NZ and demonstrates the expected performance improvements as a result of 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 disclosed operational expenditure ratio was 3.94% in and 3.71% in It is likely to rise from to to approximately 4.75% due to the impact of additional operational expenditure for the vegetation management programme. From 2013 and beyond when vegetation management is planned to return to 2009 expenditure levels, it should reduce significantly as a result of the reduced maintenance costs and the increased asset replacement due to the impact of the Network Development Programme. It is nevertheless likely to remain above the levels of due to the costs incurred in the more aggressive approach to network maintenance that will be needed if the reliability targets are to be met. SERVICE LEVEL TARGET YE 2011 TARGET YE 2012 TARGET YE TARGET Operational Expenditure Ratio 4.2% 4.75% 4.75% % Table 25 Financial Service levels 88

91 4.4 Justification for Service Level Targets LEVEL OF SERVICE 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 3.1.4, 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. The 2007 review of Section 62 of the Electricity Act 1992 revised the Act, so that the obligation to supply line function services to all customers supplied as at 1 April 1993 will continue to be met by using either lines, or alternative generation after the original expiry date for this obligation of 1 April The Ministry of Economic Development (MED) provided the suggested test scenarios: Condition 1 Where Uneconomic Areas are less than 20 kva per ICP and less than 3 ICP s per km. Condition 2 Where Uneconomic Areas are less than 6500 kwh per ICP and less than 3 ICP s per km. In April 2009, Top Energy undertook a study to identify uneconomic lines using the data in the GIS in relation to the MED s 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 collated results (condition 1 scenario) revealed that 33% of the network covers just 8% of the customer base, and is considered uneconomic to own. Accordingly, the service level targets ultimately reflect the Top Energy Board s views on affordability given the high proportion of uneconomic lines. This view has been 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 2010 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 customers 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 The targeted control regime established under Part 4A of the Commerce Act 1986 and promulgated by the Commerce Act (Electricity Distribution Thresholds) Notice 2004 required each lines company to consult with their consumers on the options of price and supply quality available to those consumers during the two year periods ending on 31 March 2006 and 31 March 2008 and to take those consumers views into account when making asset management decisions. In discharging its responsibilities under the Customer Consultation requirements in Section 6(1)(c) of the Notice, Top Energy has attempted to: properly advise its consumers about the price and quality trade-offs available to them in relation to the goods and services provided by the distribution business; consult with those consumers about the quality of goods and services that they require, with reference to the price of those goods and services; properly consider the views expressed by consumers during and after that consultation; and adequately take these views into account when making asset management decisions. 89

92 LEVEL OF SERVICE The Commission did not require electricity distribution businesses to include evidence relating to customer consultation in their 2010 compliance statements. Nevertheless, as discussed below, 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 set appropriate performance targets telephone survey An independent review was carried out of a random sample of 1,000 mass market consumers. The breakdown by supply area and market segment is shown in the table below. Table 26 MARKET SEGMENT BAY OF ISLANDS NORTH SOUTH SUB-TOTAL Rural commercial Rural residential Urban commercial Urban residential Not disclosed Total ,000 Customer survey The questionnaire (included as Appendix C) 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; 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 lower than both Top Energy s historical performance and the regulatory threshold; 66% of customers would not be prepared to pay any more for a 2nd 110kV line to the Kaitaia GXP; and 90

93 LEVEL OF SERVICE 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: to focus on improving service continuity and restoration as priorities; to continue to improve the provision of restoration information in parallel with the fault restoration work; to educate consumers to do basic checks before they call and inform Top Energy of a fault; to reduce flicker and surge where practical and where resources are available; and to 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 lower than what Top Energy has achieved in recent years, and significantly lower than the regulatory threshold. This is also in line with the 5 yr SCI targets. The lowest value in any customer segment was 225 minutes. Table 27 MARKET SEGMENT BAY OF ISLANDS NORTH SOUTH Rural commercial Rural residential Urban commercial Urban residential Customer expectations - SAIDI The following conclusions are drawn from the table above a. In the BOI area rural and urban customers seem to have a similar perception of an acceptable SAIDI. b. In the North area there is a gap between what rural commercial and urban commercial customers believe is an acceptable SAIDI. c. Expectations around rural reliability appear to be greater in the BOI than in the North and South areas. Perceptions of acceptable SAIFI: Average customer expectations of acceptable perceived SAIFI is 2.4, which is significantly lower than Top Energy historical performance and the regulatory threshold. The SCI currently allows for a 5 yr SAIFI target of 4.0 to 4.7 MARKET SEGMENT BAY OF ISLANDS NORTH SOUTH Rural commercial Rural residential Urban commercial Urban residential Table 28 Customer expectations - SAIFI 91

94 LEVEL OF SERVICE The survey identified continuity of supply and prompt restoration of service to be the most important aspects of service, and Top Energy interprets quality as synonymous with reliability (ie 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 2 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. Notwithstanding this, 80% of respondents indicated a desire to see reliability improved, and Top Energy has adopted forward service targets which are markedly lower than present. The table below details the 5 year targets disclosed within the 2009 AMP for Top Energy and the peer group of companies. ELB YE 2010 YE 2011 YE 2012 YE 2013 YE 2014 Top Energy SAIDI SAIFI Eastland Network SAIDI SAIFI Electricity Ashburton SAIDI 149 Not explicitly specified in their Asset Management Plan SAIFI 1.17 as on 1 April 2009 Horizon Energy SAIDI SAIFI MainPower SAIDI SAIFI Marlborough Lines SAIDI SAIFI Northpower SAIDI Not explicitly specified in their Asset Management Plan as on 1 April SAIFI 2009 ELB YE 2010 YE 2011 YE 2012 YE 2013 YE 2014 The Lines Company SAIDI SAIFI The Power Company SAIDI Not SAIFI specified Alpine Energy SAIDI SAIFI Peer Group Average SAIDI Table 29 SAIFI Network performance targets compared with the peer group The above table demonstrates that the TEN disclosed targets within its 2009 Asset Management Plan, although decreasing at a significant annual rate, were significantly higher than the peer group average over the five year target period. 92

95 LEVEL OF SERVICE It is not unreasonable to assume that the current strategies in place for vegetation management, lightning remediation and condition monitoring together with the recent installation of network automation equipment will reduce Top Energy s SAIDI to between 300 and 350 minutes per annum. Top Energy is, however, significantly exposed with the level of service achievable for sections of our sub-transmission system serviced by single circuit feeds that would likely prevent us from achieving an annual figure below this rate prior to the completion of the Network Development Plan. However the Network Development Plan is expected to drive further improvements in reliability both by increasing the reliability of the sub-transmission network and also by improving the reliability of the distribution network by creating shorter feeders with fewer customers affected by individual faults High user consultation In 2008 Top Energy engaged a specialist energy consultant to engage by phone with 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, on an annual basis, holds detailed discussions with each of its three major industrial customers 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 for and specified in Section above are a direct result of the analysis of the 2009 consumer survey results. They 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. Further service level improvements beyond are expected to result from the impact of the Network Development Plan described in Section 5 of this AMP Justification for Asset Performance and Efficiency Targets Loss Ratio The loss ratio targets for and , as specified in Table 24, reflect the current loss ratio of the network. Improvements beyond are expected to result from the impact of the Network Development Plan described in Section Operational Expenditure Ratio Top Energy s disclosed operational expenditure ratio was 3.94% in and 3.71% in It is likely to rise in to to approximately 4.75% due to the impact of additional operational expenditure for the vegetation management programme. From 2013 and beyond when vegetation management is planned to return to 2009 expenditure levels, it should reduce significantly as a result of the reduced maintenance costs and the increased asset replacement due to the impact of the Network Development Programme. It is nevertheless likely to remain above the levels of due to the costs incurred in the more aggressive approach to network maintenance that will be needed if the reliability targets are to be met. 93

96 Section 5 Network Development Planning 5.1 Planned Expenditure Routine and Preventative Maintenance Refurbishment and Renewal Maintenance Specific Customer Initiated Projects Augmentation Planning Criteria Voltage Criteria Security of Supply Network Reliability Level Network Capacity Requirements Network Protection Requirements Distribution Policy on Acquisition of New Assets Project Prioritisation Methodology Assess Importance and Identify Options Prioritisation Matrix for Network Expenditure Demand Forecast Demand forecast methodology Demand forecasting model Regional after diversity demand forecast Zone Substation after Diversity Maximum Demand Forecast kV Feeder Demand Forecast Uncertainties in the demand forecast Distributed Generation (Embedded Generation) Non-network Options Network Development Plan Grid Exit Points Network Development Plan Overview Capacity/Security Issues System Enhancement Options Project Time line and Costs Detailed project Descriptions and Development Timeline kV Sub-transmission Line Projects (inc 110kV) /11kV Substations Distribution Network

97 5.9.4 Network Wide Projects Independent Review of the Network Development Plan

98 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 56 and table 30 illustrates the predicted levels of expenditure for the planning period, separating the expenditure into the categories mentioned above. 30,000,000 Operational Expenditure: Fault and Emergency Maintenance Operational Expenditure: 25,000,000 Refurbishment and Renewal Maintenance Operational Expenditure: 20,000,000 Routine and Preventative Maintenance Capital Expenditure on Non- 15,000,000 System Fixed Assets 10,000,000 5,000,000 0 Capital Expenditure: Asset Relocations Capital Expenditure: Asset Replacement and Renewal Capital Expenditure: Reliability, Safety and Environment Capital Expenditure: System Growth Figure 56 Expenditure Forecast (FYE2012 to FYE2021) 96

99 YEAR 1 YEAR 2 YEAR 3 YEAR 4 YEAR 5 FOR YEAR ENDED Capital Expenditure: Customer Connection 1,000,000 1,200,000 1,500,000 1,500,000 1,500,000 Capital Expenditure: System Growth 6,686,006 8,389,612 8,179,680 7,725,343 7,580,000 Capital Expenditure: Reliability, Safety and Environment Capital Expenditure: Asset Replacement and Renewal 5,392,500 2,550,000 1,950,000 2,920, ,000 4,085,000 4,045,000 4,085,000 4,045,000 4,085,000 Capital Expenditure: Asset Relocations 175, , , , ,000 Subtotal - Capital Expenditure on asset management 17,338,506 16,409,612 15,964,680 16,440,343 14,150,000 Capital Expenditure on Non-System Fixed Assets 1,250,000 55,125 57,881 60,775 63,814 Operational Expenditure: Routine and Preventative Maintenance Operational Expenditure: Refurbishment and Renewal Maintenance Operational Expenditure: Fault and Emergency Maintenance Subtotal - Operational Expenditure on asset management 4,100,000 2,100,000 2,100,000 2,100,000 2,100,000 1,077, , ,000 1,020,000 1,183, , , , , ,000 6,077,500 3,720,000 3,820,000 4,020,000 4,183,500 Total direct expenditure on distribution network 24,666,006 20,184,737 19,842,561 20,521,118 18,397,314 YEAR 6 YEAR 7 YEAR 8 YEAR 9 YEAR 10 FOR YEAR ENDED Capital Expenditure: Customer Connection 1,500,000 1,500,000 1,500,000 1,500,000 1,500,000 Capital Expenditure: System Growth 6,882,316 7,421,280 5,965,012 8,271,912 9,736,264 Capital Expenditure: Reliability, Safety and Environment Capital Expenditure: Asset Replacement and Renewal 1,700,000 1,091, , , ,500 4,045,000 4,085,000 4,045,000 4,085,000 6,365,000 Capital Expenditure: Asset Relocations 250, , , , ,000 Subtotal - Capital Expenditure on asset management 14,377,316 14,347,592 12,319,512 15,130,412 18,223,764 97

100 YEAR 6 YEAR 7 YEAR 8 YEAR 9 YEAR 10 FOR YEAR ENDED Capital Expenditure on Non-System Fixed Assets 67,005 70,355 73,873 77,566 81,444 Operational Expenditure: Routine and Preventative Maintenance Operational Expenditure: Refurbishment and Renewal Maintenance Operational Expenditure: Fault and Emergency Maintenance Subtotal - Operational Expenditure on asset management 2,100,000 2,100,000 2,100,000 2,100,000 2,100,000 1,102,500 1,282,500 1,410,000 1,520,000 1,745, , , , , ,000 4,102,500 4,282,500 4,410,000 4,520,000 4,745,000 Total direct expenditure on distribution network 18,546,821 18,700,447 16,803,385 19,727,978 23,050,208 Table 30 Expenditure Forecast 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 56 and Table 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 nonnetwork 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 98

101 discretion, supplement the requirements of a customer driven project with an internally funded network refurbishment or augmentation Augmentation Augmentation includes 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 related to network augmentation 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, the choice of augmentation projects adopted 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 the 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 condition; 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 a) Zone sub and Distribution Transformer In order to control the system voltage within the specified limit, Top Energy purchases all Zone Substations transformers with 15 step On Load Tap Changer (OLTC) facility with tap ranges from % (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 six step Off Load Tap Changer facility with -7.5% (Voltage Boost) to +5% (Voltage Buck). b) Distribution Voltage Regulator 99

102 Top Energy uses two different types of distribution voltage regulators on long rural distribution feeders. 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. c) 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. d) Overhead line upgrades Top Energy is predominantly a rural network with long radial feeders with 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 the 2 wire and / or SWER lines to 3 wire; increase the conductor size at critical areas to remove constraints; rearrange feeder routes close to substations in order to share load more evenly; upgrade the operating voltage on heavily loaded sections of line, eg. from 11kV to 22kV; use of capacitors and regulators Security of Supply TEN s security of supply standard drives not only existing asset improvements, but also the design criteria of network extensions and improvements. The security of supply standards adopted by TEN are detailed in table 31 overleaf. The network does not currently conform to these security of supply standards at zone substation level due mainly to protection constraints that limit the way the 33kV sub-transmission network can be operated. In all cases, the sub-transmission system is currently run in a split bus arrangement with one line feeding each half of a substation. This means that in the event of a fault on the incoming line, approximately half of the customers supplied by the substation would be without supply until the network can be reconfigured by switching. In extreme cases it may not be possible to restore supply to some customers until a repair has been undertaken. The inability to maintain uninterrupted supply at large zone substations in the event of a single element fault is a significant concern to Top Energy and is being addressed as part of the Network Development Plan detailed later in this section. It is the intention of this plan to achieve the Security of Supply standard detailed above within the 10 year planning period adopted within this plan. Top Energy owns and operates a 7.5 MVA mobile transformer unit to provide extra security to the Network. This unit is currently situated at Moerewa substation, which otherwise would not have a backup transformer. 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 shown in Table 32. These times include 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 table also shows available back up time for zone substations with two transformer banks. 100

103 TARGET LEVEL AT SUBSTATIONS IN THE EVENT OF AN OUTAGE OF ONE MAJOR ELEMENT OF THE NETWORK LOAD WOULD BE RESTORED TO THE 11KV LEVEL ACCORDING TO THE FOLLOWING TARGETS: 4 >12MVA Or >6000 ICPs Supply would be uninterrupted. However load may still need to be transferred by switching if necessary to avoid exceeding ratings MVA Or ICPs MVA Or ICPs Supply would be restored within 30 minutes by switching at sub-transmission and / or distribution level. Supply would be restored to 50% within 3 hrs, by switching after the faulted element is isolated. Supply to the remainder might not be restored until the faulty element is repaired or replaced. 1 <3MVA or <1500 ICPs Supply would not be restored until the faulty element is repaired or replaced. Table 31 Top Energy Security Standard SUBSTATION TRANSFORMER FAILURE BACK UP TO AFFECTED TRANSFORMER TIME REQUIRED TO RESTORE SUPPLY (HRS) Southern GXP Kaikohe T1 T2 Switching Time T2 T1 Switching Time Kawakawa T1 T2 Switching Time T2 T1 Switching Time Moerewa T1 Mobile Sub Switching Time Mobile Sub T1 Switching Time 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 GXP Okahu Rd T1 T2 Switching Time T2 T1 Switching Time Taipa T1 Mobile Sub 9.5 Pukenui T1 Mobile Sub

104 NPL T1 T2 Switching Time T2 T1 Switching Time Table 32 Zone Substation Transformer backup and Timings Network Reliability Level Network Reliability level is defined and monitored using accepted industry standards and the indicators used are described in Section 4 of this plan Network Capacity Requirements. 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 deg Underground cables In Duct Circuit Breakers Nominal Table 33 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 much better data on asset utilisation and, over time, will allow improved modelling of the network. Improved modelling will mean improved asset management New Equipment Standards In order to maximise cost efficiencies and reduce stock holding Top Energy Networks 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 considerations. Transformers may be 1, 2, or 3 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. 102

105 Poles are all pre-stressed I section poles. Wood poles are being progressively phased out of the network. Overhead conductors are currently all aluminium conductor (AAC) except where long spans demand higher tensions. For these applications the equivalent steel reinforced aluminium conductor (ACSR) conductor is used. For new projects where high capacity 33kV is required selenium AAC conductor 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. 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 actual current carrying capacity. The company monitors the voltage level along its feeders both with sophisticated computer models and physically by installing data logging devices. Investment in arrangements to meet the legally set voltage requirements for the forecasted 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. 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 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 project implementation Assess Importance and Identify Options Top Energy receives information for work required on the Network from the following sources. Top Energy Network Staff; Top Energy Control Centre; Top Energy Contracting Services; Network Lines Inspectors; Maintenance Manager; Network modelling and study; Customers; and 103

106 FNDC Plans. All the projects in the project database are reviewed by the appropriate project manager. For each project that is being considered for inclusion in the AMP, the appropriate project manager completes a project planning initiation sheet that: Fully describes the issue and / or opportunity; Identifies the primary driver of the issue (eg. Voltage compliance, Security, Reliability); Describes the proposed solution and the options considered including non-network solutions; Estimates the cost of the proposed solution; Describes he benefits of the solution to Top Energy, its customers and the community; Provides a rating in each of the categories within the prioritisation matrix indicating the impact on the business drivers. The rating 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 57 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 Financial The Company needs Revenue Control of costs Return on Investment Customers Meeting customers needs from a network or electrical system perspective Supply capacity Quality of supply Reliability of supply Security of supply Community 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 57 below. They are used as the basis for the prioritisation matrix shown in Figure 58, which in turn can be used 104

107 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 57 Network Performance Scorecard 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-todate 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 105

108 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 a. Load Growth b. Overcoming Existing Constraints c. Customer Generated Work d. LV augmentation e. Distribution sub upgrades Reliability Quality Security 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) Ensuring Regulatory Compliance Safety Staff and Contractors 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. 106

109 NETWORK DEVELOPMENT PLANNING Network Works Prioritisation Matrix Ranking Not applicable 0 Low 1 Medium 2 High 3 Very High 4 High/Extreme 5 Score Overall Score Community & Customer Perception Financial Benefit to Business Impact on System Performance Regulatory Compliance Improved Improved Improved Reduction in Reduction in Reduction in Safety Customer Visual Company Maintenance Operational Future Capital Capacity Reliability Quality Security Staff & Environmental Public Responsiveness Amenity Reputation Costs Costs Costs Contractors Total Score 10 Total Score 13 Total Score 17 Total Score 11 Weighting 0.2 Weighting 0.2 Weighting 0.3 Weighting 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 Not applicable No payback ever Payback within 20 years Payback within 10 years Payback expected within 5 years Payback expected within 2 years Not applicable 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 Not applicable 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 Figure 58 Example of Network Prioritisation Matrix 5-107

110 NETWORK DEVELOPMENT PLANNING 5.6 Demand Forecast Demand forecast methodology Demand forecasts estimate the amount of electricity required in different parts of the geographical area served by Top Energy. TEN uses an internally developed spreadsheet based model to forecast the future demand on the network for the planning period. The demand forecast then forms the basis for network development planning for the planning period. 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 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. 108

111 NETWORK DEVELOPMENT PLANNING 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 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 as 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 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 Demand forecasting model The forecasting model uses a linear trend forecasting method for forward projection of ICPs per feeder for the entire network. It calculates load per customer based on five years of historical feeder maximum demand data (excluding large industrial consumers) and annual changes in ICP numbers to make forward load projections for each feeder. From the projected number of ICPs per feeder and load per customer value as calculated in step 1, the model calculates maximum demand for each feeder using the following equation as per TEN s design standard. PMax = CADMD x [ /(1+N)]*N Where, N = Number of ICP CADMD = Customer After Diversity Maximum Demand The final feeder load projections are made after adding new or existing specifically identified large loads (such as large subdivisions and industrial loads) to the results of step 2, The feeder forecast loads are then aggregated at zone substation level by applying a historical diversity factor to forecast zone substation maximum demand. The same approach is taken to forecast at GXP level Regional after diversity demand forecast The long term (10 year), after diversity maximum demand (MVA) for the network is forecasted in Figure 60 and the compound annual growth rate (CAGR) is forecast as shown in Figure 59. It can been seen that Top Energy demand decreased in 2008 compared with 2007 which is due to the global recession and an energy saving campaign in There has been an increase in demand in with forecast of 2.1% growth rate. Note that these growth projections are after diversity demand and so will not correspond to the undiversified feeder peak demands which for total almost 70MVA. Individual zone substation and feeder peak demands must be taken into account where appropriate in network development planning. 109

112 Peak Demand (MW) NETWORK DEVELOPMENT PLANNING % CAGR FOR 20 YEARS NORTHERN (KTA) 1.70% SOUTHERN (KOE) 2.30% NETWORK 2.10% Figure 59 Percentage of CAGR for 20 years Kaitaia Kaikohe Network Figure 60 Regional after Diversity Maximum Demand Growth Profile ( ) Zone Substation Maximum Demand Forecast The load growth projections are reviewed at zone substation level to identify any potential loading or security of supply issues. Table 34 shows the actual load for each zone substation for FYE 2010 and a ten year projection for FYE2011 to FYE2021. In the southern network, four new 33/11kV substations are proposed in the planning period and the impact of these new substations on the forecast load on existing substations is reflected in the table. Kerikeri, Kaeo and Purerua substations are proposed in 2015, 2017 and 2021 respectively and will be taking load from Waipapa substation. 110

113 NETWORK DEVELOPMENT PLANNING Zone Sub Maximum Demand (MVA) Year ending SOUTHERN KAIKOHE KAWAKAWA MOEREWA WAIPAPA OMANAIA HARURU Mt POKAKA KERIKERI KAEO PURERUA NORTHERN OKAHU TAIPA PUKENUI NPL Table 34 Zone Substation Maximum Demand (MVA) Figure 61 and Figure 62 represent percentage of CAGR (10 years) for individual Zone Substation in Southern and Northern Network respectively. Mt Pokaka is not shown because it is primarily supplies an industrial customer and the load growth over the planning period is expected to be small. 111

114 % CAGR % CAGR NETWORK DEVELOPMENT PLANNING Southern Zone Substation Growth ( ) 4.5% 4.0% 3.5% 3.0% 2.5% 2.0% 1.5% 1.0% 0.5% 0.0% Waipapa Haruru Kawakawa Omanaia Kaikohe Moerewa Existing Zone Substations. Figure 61 Southern Network ZS % CAGR ( ) 2.5% Northern Zone Substation Growth ( ) 2.0% 1.5% 1.0% 0.5% 0.0% NPL Taipa Okahu Pukenui Existing Zone Substations. Figure 62 Northern Network Zone Substation percentage of CAGR ( ) From the above load growth projections, it is possible to compare the level of security of supply that should be provided at a given location against the present levels, thus identifying potential reinforcement projects. Refer to section for the definitions of the Security Levels. This is illustrated in Table 35 below, which shows that Top Energy s network security standards are currently not met at Waipapa, NPL and Taipa substations. ZONE SUB SECURITY LEVELS Year ending SOUTHERN Kaikohe Kawakawa

115 NETWORK DEVELOPMENT PLANNING Moerewa Mt Pokaka Waipapa Omanaia Haruru NORTHERN Okahu Taipa Pukenui NPL Table 35 Top Energy Individual Zone Substation Security Table 36 compares the present levels of firm and switched capacities for each existing substation, against the present and projected loads, to identify where reinforcement may be required. AFTER DIVERSITY MAXIMUM DEMAND (MVA) AND EXISTING FIRM/SWITCHED CAPACITY (MVA) Zone Sub Existing Capacity Loads Firm (N-1) 11kV Switched Capacity SOUTHERN KAIKOHE KAWAKAWA MOEREWA WAIPAPA MT POKAKA OMANAIA HARURU NORTHERN OKAHU TAIPA PUKENUI NPL Note 1: Offloaded by new Kerikeri substation Note 2: Offloaded by new Kaeo and Purerua substations Table 36 Capacity Comparisons The possible range of projects, to address issues raised by the above analysis is discussed in Chapter 5. The identification of a shortfall in security and inclusion of relevant projects in the Network Development Plan does not necessarily mean that work will be undertaken to address the issue. Firstly, the economic justification for the proposed work needs to be established. Secondly, other options, such as distributed generation, demand side management, improvement in customers power factor may well prove to be cost effective. However the inclusion 113

116 Purerua Onewhero Riverview Aerodrome Rd Rangiahua Whangaroa Russell Totara Nth Horeke Joyces Rd China Clay Tii Bay Taheke Ohaewai Puketona Opua Opononi Rawene Moerewa Pokapu Awarua Kaikohe Towai Kawakawa Tau block NRCF AFFCo % CAGR NETWORK DEVELOPMENT PLANNING of network upgrades in the Network Development Plan included in Section 5 of this AMP provides a baseline for comparison with other options kV Feeder Demand Forecast There is considerable variation in the individual feeder load patterns across the Top Energy supply region. Growth varies across 11kV feeders from those with almost no growth to some, especially in eastern coastal areas, which are experiencing significant growth. Feeders are monitored individually and any changes to open points or any reinforcements made as individual problems are identified. Figure 63 and Figure 64 show the forecasted feeder growth (percentage of CAGR) for the next ten years. Appendix D shows the forward load projections for individual feeders in Southern and Northern Network for ten years time frame. 6.3% Southern Network Feeder Growth ( ) 5.4% 4.5% 3.6% 2.7% 1.8% 0.9% 0.0% Feeders. Figure 63 Southern Network Feeder Percentage of CAGR ( ) 114

117 Mangonui Te Kao North Rd Oxford St Pukenui South Tokerau South rd Kaitaia West Herekino Oruru Awanui Redan Rd Pukepoto North Mill2 Triboard1 Triboard2 % CAGR NETWORK DEVELOPMENT PLANNING Northern Network Feeder Growth ( ) 3.50% 3.00% 2.50% 2.00% 1.50% 1.00% 0.50% 0.00% Feeders. Figure 64 Northern network Feeder percentage of CAGR ( ) The Northern area feeder growth reflects feedback from the major industrial Customer, Juken Nissho, that there is no growth forecast for the planning period Uncertainties in the demand forecast There are three main 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 equivalent to small to medium size townships. Should the subdivisions proceed an additional 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. The Network Development Plan includes the Purerua substation at the very end of the planning period but does not include the Karikari substation. It is likely that the zone substation and associated line works in these areas will need to be either accelerated or deferred in accordance with the developers plans. The third major project is the Affco Dairy Factory, which is a planned 4MVA installation alongside the existing Affco freezing works in Moerewa. This project depends on both the resource planning process and the overseas dairy sales market. At this stage the chances of this project proceeding are considered too uncertain. Hence the load is not included in the forecast and there is no provision in the Network Development Plan for augmenting the zone substation transformer capacity at Moerewa. 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 undertaken which have not yet resulted in connected load, but which could be very quickly add to the present demand once the recession lifts in the region and building recommences. These developments can be accommodated by the Network Development Plan as formulated in this AMP Distributed Generation (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: 115

118 NETWORK DEVELOPMENT PLANNING 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 fast as possible, All technical and safety standards relating to DG are based on industry practice, and All relevant legislation and regulatory requirements are adhered to. TEN reserves right to limit the total capacity of DG connected different parts of its network (in particular to each 11kV/22kV feeder). DG installations will be subject to normal industry connection requirements, in particular those outlined in the Electricity Governance Rules. Top Energy has adopted 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 Table 37); commercial terms; technical standards; liabilities of Top Energy and the applicant, and health and safety management. 116

119 NETWORK DEVELOPMENT PLANNING Table 37 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. Distributed Generation (> 5MW): Top Energy encourages the provision of embedded generation by introducing potential consumers to suppliers, consultants, and major energy companies who can assist in the development of such schemes. Top Energy has demonstrated its commitment to distributed generation by establishing the Ngawha Power Station. The generation capacity expansion of Ngawha to 25MW is complete and was commissioned in the financial year. 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 cost effective alternative to grid extension. The following options can be considered as for dispersed generation; Use of small 2-5kW generators (Solid, gaseous and/ or liquid Fuel) f. Solar Panels (with battery storage) g. Mini and Micro- Hydroelectric h. Wind Power ( with battery storage) i. Island generators (<300kW) 117

120 NETWORK DEVELOPMENT PLANNING 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 and on a number of occasions has used mobile generators to retain supply to customers when the network is not available. However in most instances, the costs to implement alternate systems make it difficult to convince customers that the alternative is better value for money. This is usually due to the following factors. The physical distances between customers often requires a significant network to be retained or built; The capital cost and life expectancy of the technologies; The 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. In addition, Top Energy has identified its requirements for the connection of distributed generation to the system. The policy and requirements for the distributed generation are available on Top Energy s website. A factor to consider in relation to distributed generation is that supply to uneconomic customers may create a business opportunity to establish distributed generation solutions, in place of upgrading old lines. The viability of distributed generation for this application will likely depend on the technology available at the time a line upgrade is required and the life cycle costs of operating and maintaining the plant to ensure reliable and safe operation. More information on Top energy s policies in respect to the connection of distributed generation is available on the Company s web site, 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 and 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 and therefore defer the capital investment for additional capacity. The selection of a viable DSM option starts with identification of all applicable options, 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 the 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 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, the Grid Operator 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 preset delay dependant on the levels of frequency excursion on the system. Table 38 below shows the operating arrangements of these two load blocks. 118

121 NETWORK DEVELOPMENT PLANNING Frequency Excursion Tripping Time - Seconds Table 38 Block 1 Block Hz Hz 4 4 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 table 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 NORTHERN NETWORK OKAHU South Road Kaitaia West Herekino NPL Awanui TAIPA Oruru Tokarau Mangonui PUKENUI Te Kao Pukenui South Table 39 Top Energy Emergency Load Shedding Feeder Identification 119

122 Demand (MW) NETWORK DEVELOPMENT PLANNING 5.7 Network Development Plan Grid Exit Points Northern Area Kaitaia Grid Exit Point a) Demand The present peak demand at Top Energy s northern Grid Exit Point (GXP) is 26.1 MVA. The long term forecast load growth is 1.7% pa. The peak demand in 2021 is forecasted to be 31.5 MVA as shown in the figure below NPL Pukenui Taipa Okahu Rd 0 Figure 65 Kaitaia Grid Exit Point Load Growth b) Capacity The Transpower Kaitaia substation has 2 x 110kV/33kV 20MVA transformers giving 40MVA total capacity with both units running, which is adequate for the demand under normal conditions during the planning period. c) Security Supply to this GXP is by a single 110kV overhead transmission circuit, with a rating of approximately 61MVA which feeds into a single bus, two transformer substation. Given the significant population and electricity demand in the Kaitaia region, this arrangement does not provide a satisfactory level of supply security. Firstly, as there is no alternative incoming supply, in the event of an unplanned outage of the incoming overhead line, the area would be without electricity until this fault is repaired. This could be an extended period, particularly if the fault occurred in the Maungamuka ranges, where access can be difficult. Even now, there are annual scheduled supply outages to allow planned line maintenance to completed. While these outages are scheduled for periods of low demand, they still result in a total loss of supply to the region. The second issue is the size and age of the transformers. If a fault occurred on one of the transformer banks, the remaining bank would have insufficient capacity to supply the current peak demand. While such an event would not result in a complete loss of supply, it could result in the electricity having to be rationed. This would mean that some customers would lose supply for short periods at times of high demand as managed outages were implemented on a rolling basis to limit the total demand to within the capacity of the good transformer. Top Energy has had the security of supply to the Kaitaia region under review for a number of years. It has considered a number of options including the potential for wind farms and other sources of generation to address the issue. However the variable power output of wind farms, and the lack of alternative fuel sources in the region has led Top Energy to conclude that grid augmentation is the most cost effective solution given the size of the load and the level of reliability required. On this basis, Top Energy is currently in the final stages of negotiating a 120

123 Demand (MW) NETWORK DEVELOPMENT PLANNING transmission development plan that it is confident will provide adequate security of supply to the Kaitaia region for the foreseeable future. This plan, which is discussed in more detail in Section 5.8, involves the replacement of the existing transformers at Kaitaia with new larger units and the construction of a new 110 kv single circuit line around the east coast, bypassing the Maungamukas Southern Area Fed from Kaikohe Grid Exit Point and Ngawha The present peak demand on Top Energy s southern network exceeds 45 MW. This peak demand is supplied by the Kaikohe GXP and the embedded Ngawha power station. Up to 25 MW of load is supplied by the Ngawha power station in normal operation and the balance load is supplied by the GXP. The overall long term forecasted load growth is 2.30% p.a. for the planning period. Load in 2021 is forecasted, for the Southern network, to be 60.5 MVA or 34.8 MVA net with the Ngawha power station running at its average capacity of 25.7 MVA Purerua Kaeo Kerikeri Mt Pokaka Haruru Omanaia Waipapa Moerewa Kawakawa Kaikohe Figure 66 Kaikohe Grid Exit Point Feeder Load Growth

124 Demand (MW) NETWORK DEVELOPMENT PLANNING Ngawha Kaikohe GXP 10 0 Figure 67 Kaikohe Grid Exit Point Load Growth a) Capacity The Transpower Kaikohe substation consists of two transformers rated respectively at 30 MVA and 50 MVA. This capacity is sufficient to supply the normal load for the planning period. b) Security The Kaikohe GXP substation has two transformers, and a single bus, served by a double circuit 110kV line, each circuit rated at 63/77MVA (summer / winter) rating. In addition to supplying Kaikohe GXP, the Kaitaia GXP is also fed by a spur line from Kaikohe; thus the total load on the double circuit 110kV line into Kaikohe is potentially the sum of the two GXP s without Ngawha generation which after diversity totals approximately 73MVA. Top Energy s peak demand is set in winter when the higher incoming line rating applies. Notwithstanding this, the ability to maintain supply to all connected customers at times of high demand, particularly in summer, in the event of the loss of one of the incoming 110 kv circuits is becoming marginal without the support of Ngawha generation. c) GXP Transformer Outages: T3 (50MVA) is adequately rated to supply the full local load in the event of T2 being out of service. However if T3 is out of service then T2 rated at 30MVA will be overloaded by some 28% at present, although this may be alleviated by available generation from Ngawha. Whilst such a level of overload should be able to be accommodated for a short period, as demand continues to grow this becomes less acceptable. The timing of an upgrade is being discussed with Transpower but the actual performance of the upgraded Ngawha generation will be critical to the timing of any upgrade. d) Transmission Line Outages As noted it is necessary to consider the combined load of Kaikohe and Kaitaia when assessing the capability of the transmission lines into Kaikohe. The combined ADMD load at present is 73.5 MVA which is predicted to increase to over 90MVA by If either incoming circuit (63/77MVA) is lost then the remaining circuit will supply the peak loads predicted in the next five years. If Ngawha can supply its full 25 MVA output throughout the contingency, the total peak loads can easily be maintained for the duration of the plan. However this is dependent on the Ngawha generation being able to retain synchronisation during the initial fault. 122

125 NETWORK DEVELOPMENT PLANNING The Ngawha generation plant cannot remain operational through a fault that causes both transmission lines to trip, which occurred in 2009 due to the Auckland fork lift truck incident. In this case, supply was lost to the entire Top Energy Network. Although such N-2 faults are possible they are not common. Top Energy Network will continue to work with Transpower, Ngawha Generation, and potential generators, and customers to find acceptable timely solutions to mitigate the consequences of transmission line failure. 5.8 Transmission Development Plan The 2010 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. In this AMP, Top Energy is pleased to announce that it is also planning to supplement the sub-transmission development plan with a transmission development plan designed to address high level security of supply issues outside the scope of the sub-transmission plan and, in particular, the security of supply to the Kaitaia region. As explained below, the implementation of this plan is dependent on the outcome of current negotiations with Transpower over the future of the transmission assets that supply Top Energy. 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 this AMP is focused on providing subtransmission capacity for expansion and appropriate security for Far North customers, there has still been significant dissatisfaction expressed by customers in the Kaitaia district in relation to the lack of transmission security and the loss of supply which has occurred in recent years. This has resulted in complaints to the Minister for Energy, with customers demanding the construction of a second transmission line. Over the last two years, Top Energy has therefore 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. 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 represents a $10 million saving over the direct route proposed by Transpower, since large portion of the coastal route would still be required for 33kV sub- 123

126 NETWORK DEVELOPMENT PLANNING transmission 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 would not only achievethe capacity and security of supply requirements of the existing 33kV plan but would have 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 would provide 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 has agreed that the lowest cost and best technical solution should be adopted and a proposal for Transpower to transfer its existing assets in the Far North to Top Energy, whilst Top Energy constructs the second transmission line to Kaitaia is being negotiated. The proposal is subject to regulatory approval of transmission pricing issues by the Commerce Commission. The transfer, which is planned to take place later in FYE2012, 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 equipment, 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. Both the transmission asset transfer and the construction of a new 110 kv circuit around the East Coast, together with the planned Transpower capital investment works, will have a major impact on the detailed design and timing of the sub-transmission development plan that is already in place. These changes, which are dependent on this transfer proposal being approved by the Commerce Commission, are still being formulated and are not described in detail in this AMP, which is based on last year s plan and assumes that the second transmission circuit to Kaitaia would use Transpower s direct route. However, an indicative plan of how the future Top Energy transmission and sub-transmission network might appear, should this project proceed, is shown in Figure 68. Assuming the east coast transmission option is approved and the transmission asset transfer proceeds, the 2012 AMP will present an integrated development plan, covering the planned development of both transmission and subtransmission assets. 124

127 NETWORK DEVELOPMENT PLANNING Figure 68: Possible Future Network Arrangement 125

128 NETWORK DEVELOPMENT PLANNING 5.9 Network Development Plan Overview The Network Development Plan undertakes to achieve the security of supply standards detailed in Table 40, based on the size of the load and criticality of customers or customer groups. In most cases these security standards at zone substation level are currently not met. This means that faults on the 33kV subtransmission system will potentially cause customer outages for unacceptably long periods of time. TARGET LEVEL AT SUBSTATIONS In the event of an outage of one major element of the network load would be restored to the 11kv level according to the following targets: 4 >12MVA Or >6000 ICPs Supply would be uninterrupted. However load may still need to be transferred by switching if necessary to avoid exceeding ratings MVA Or ICPs MVA Or ICPs Supply would be restored within 30 minutes by switching at substation-transmission and/or distribution level. Supply would be restored to 50% within 3 hours, by switching after the faulted element is isolated. Supply to the remainder might not be restored until the faulty element is repaired or replaced. 1 <3MVA or <1500 ICPs Supply would not be restored until the faulty element is repaired or replaced. Table 40 Top Energy Published Target levels for Security of Supply The 33kV system supplying Waipapa substation is currently of insufficient capacity to meet projected short term future demand. System modelling has predicted that the system could be unable to maintain voltage at acceptable levels and power supply could be lost to 6500 customers under some relatively modest fault conditions. Plans have been developed for the installation of a number of new zone substations that will provide increased supply capacity where required, as well as new interconnections to improve security of supply. These are described in detail later in this section. The timing of these projects is critical to ensure capacity and security objectives are met before system criticality levels are reached. These new zone substations are also needed to increase the capacity of the distribution network by increasing the number of locations where power is injected into the system. They are also expected to increase distribution network reliability by shortening the length of many distribution feeders and reducing the number of customers affected by a distribution network fault. Network reliability at 33kV will also be improved with the adoption of modern unit protection schemes, controlling fault events on the interconnected network. An external specialist protection consultancy has been engaged to assist with developing cost effective strategies for this over the development planning period. The present 33kV system in the southern area consists of a series of dual circuit lines supplying zone substations in Waipapa, Haruru, Moerewa and Kawakawa. The busbars within these substations are operated in a split (or open) configuration, resulting in each half of the substation being fed from different feeders, most shared with other zone substations. Hence the failure of any one of the primary 33 kv sub transmission lines will result in the loss of supply for at least half of one substation. For most faults, more than one substation will be affected. Omanaia to the west is a special case; it is supplied by one feeder with little scope for improvement in security in the medium to long term without the building of a second line. Kaikohe is also supplied from a single overhead line from the Kaikohe GXP, although this line is very short as Top Energy s substation is on the same site as the GXP. 126

129 NETWORK DEVELOPMENT PLANNING A further weakness is the protection constraint that necessitates an inter-trip on the two 33 kv lines to which Ngawha is connected. Hence if the circuit breaker at the Kaikohe GXP that feeds one of these lines trips as a result of a fault, the second line will also trip, causing further loss of supply. A recent single bird strike close to the Kaikohe substation on one 33kV pole resulted in the tripping of both Transpower breakers and the disconnection of Ngawha, half of Waipapa, Kerikeri, Moerewa and Kawakawa for 2 ½ hours. Weak Areas of the Network Aging Transpower S/S Assets Kaitaia 110kV Pukenui Okahu Rd Taipa Single Circuit 33kV NPL Reaching Maximum Capacity / Segregated Busbar Single Circuit 11kV Single Circuit 110kV Intertripping Radial 33kV Waipapa Aging Transpower S/S Assets Kaikohe 110kV Haruru Ngawha 40 MW Moerewa Russell Maungatapere Omanaia Single Circuit 33kV Kawakawa Figure 68 Weak Areas of the Network Capacity/Security Issues Transformer Capacity In the southern area zone substations (Omanaia excluded) have two transformers each with sufficient capacity such that if one fails the other is capable of carrying the full substation demand, after switching. Thus, in terms of transformer capacity, the zone substations operate in an interrupted n-1 security configuration i.e. in the event of 1 failing there is sufficient capacity in the second to supply all connected load. The exceptions to this are at Waipapa which will exceed the n-1 capacity capability in , and Kawakawa which has already exceeded the n-1 demand threshold. Moerewa only meets the n-1 criteria by virtue of the temporary installation of the mobile substation. Transformer capacity issues are either rectified by increasing the size of the existing transformers, if the rating of the switchgear allows, or by building an additional zone substation capacity in new load areas. New zone substations typically take 4 years to construct, 2 years for land acquisition and consenting plus a further 2 years for construction. Transformers have a minimum lead time of 9 months. 127

130 s / / Line constraints NETWORK DEVELOPMENT PLANNING Although two 33 kv lines supply power to each zone substation in the southern area these are connected in a radial configuration. Philosophically this has been done to reduce the extent of an outage should a fault occur on one section of line. However, a consequence is that any 33 kv line fault will cause a loss of supply to customers connected to the affected side of a substation until switching is undertaken to temporarily restore supply. See Figure 70 below. KAIKOHE x 7 KM SWITCHING STATION x R x WAIPAPA 3,370 / 7 KM x NGAWHA x 7 KM x R x R x x x HARURU 1,381 MOEREWA 413 KAWAKAWA 1,490 Figure 69 Ngawha to Kaikohe connection arrangement There is some general interconnectivity between 33kV circuits. Under fault conditions, alternative supply options to substations are available, which enable faster supply restoration and a means by which faulty sections of line can be isolated. Capacity of the majority of these lines however is insufficient to supply the present peak demand under a fault scenario. Consequently, procedures are in place to initiate load shedding in order to maintain quality of supply in situations where the transformer tap changer mechanism installed at a substation is unable to correct for statutory voltage due to an insufficient range of adjustment. The predominant factor limiting 33kV subtransmission capacity in the southern area is conductor size. Nearly half of all 33kV circuits have been constructed with conductors of a smaller size than the current TEN standards for 33kV construction. Re-conductoring sections of the network is planned to remove some of the short term capacity bottlenecks. However, the incremental gains achieved by widespread re-conductoring are not considered to be an effective long term solution to the capacity issues in the southern area, particularly around Kerikeri and Waipapa Waipapa Zone Substation The most rapid load growth has been occurring and is predicted to continue in and around Waipapa and Kerikeri. This includes developments in Purerua, Matauri Bay, and to the south of Kerikeri (Mt Pokaka). Voltage issues currently exist at Waipapa zone substation requiring load shedding under fault conditions. Substation security will change from n-1 to n this coming year when the demand exceeds the rating of one transformer, although in the short term any overloads can be managed through load transfers and, if necessary, utilising transformer short term ratings. Two lines currently supply Waipapa, each supplying one half of the substation and with no possibility of permanent interconnection. A fault on either line will result in an outage of half of the substation. Rectifying the core issues at Waipapa will in turn resolve capacity and security issues for Kerikeri, Purerua, Kaeo, Matauri Bay, Mt Pokaka and to a certain extent Haruru and the areas to the south Protection Issues The line protection on the southern area sub-transmission network is of the over-current and earth fault type. This is rudimentary but adequate for protection of a radial network scheme. However it is designed to limit damage by ensuring the isolation of faults, without regard to maintaining continuity of supply to customers. There is a partial upgrade programme in place, to install more sophisticated protection schemes on some 33kV feeders. However the design of such schemes is not a straightforward process and is made more problematic by consistently low earth fault levels on the network. In general, sophisticated protection schemes struggle to detect and isolate faults of low intensity levels, often requiring integrated fibre or pilot cables to enable efficient inter-tripping of sectionalising breakers. 128

131 NETWORK DEVELOPMENT PLANNING External specialist consultants have been engaged to undertake a comprehensive network configuration and protection evaluation, in order to enable a realistic long term protection augmentation plan to be developed System Enhancement Options To alleviate the security and capacity issues detailed above, a comprehensive assessment of a number of potential development options for the 33kV network has been undertaken. Each option has been evaluated in terms of cost, technical advantage, environmental and social impact and the net benefits of security and capacity improvement. An initial proposal was to build a new 110kV line from Kaikohe GXP to the existing Waipapa zone substation, with a 110kV to 33kV substation at Waipapa. Although providing capacity improvement for the rapidly expanding Kerikeri / Waipapa area for the foreseeable future and beyond, on evaluation this option was found not to be cost effective, creating a gross over-capacity for a considerable period of time until the load requirements catch up. In addition, little improvement in security of supply would eventuate unless the line was built as a double circuit, a difficult accomplishment from a construction point of view, given the loading on existing 33 kv circuits. Further, building 110kV past Kerikeri airport and adjacent schools would require the undergrounding of a not insignificant portion of the line at considerable additional cost. A subsequent proposal to build this line as a dual circuit 110kV / 33kV line did little to alleviate these issues. The option chosen involves the construction of a high capacity double circuit 33kV line from Kaikohe to Wiroa just short of the Airport, which can easily and readily converted to 110kV when required (i.e built as a 110kV line but operated at 33kV initially). This line is a lower cost alternative, defers the requirement to build a 110kV substation, avoids the airport complications, places the capacity at the load centre of Kerikeri and Waipapa, and provides the N-1 security required. Existing 33kV network protection schemes have been independently reviewed and new protection architecture has been designed for the proposed new network. This protection redesign coupled with the expanded, reinforced and reconfigured 33kV network will improve security of supply, particularly for customers in the Haruru, Kawakawa and Moerewa areas. Increases in fault currents for example will ensure protection will operate correctly, and operating the system in closed rings with unit protection will clear faults without causing outages. The Russell peninsular presents its own unique set of challenges due to the nature of the load, the rate of customer growth and the remoteness of the area. Several options to provide the capacity and security of supply demanded have been explored, including fixed and mobile local (diesel) generation, a new submarine cable from Paihia to Russell, and conversion of the feeder to 22kV. Conversion of the existing feeder to 22 kv and the installation of a new 22kV submarine cable appears to be the most cost effective long term option and has been included in the Network Development Plan. Using load flow modelling different 33kV network re-configuration options have been assessed, and potential new sites for zone substations evaluated. The outcome of the modelling has new substations proposed for regions of maximum load growth, and high capacity interconnecting lines and comprehensive protection schemes to provide the best and most effective capacity and security of supply for the region. The Network Development Plan set out in this AMP therefore involves: The construction of a high capacity 110kV transmission line from Kaikohe to Wiroa, which will initially be operated at 33 kv; Construction of new zone substations at Kerikeri, Kaeo and possibly Purerua and Karikari; Construction of over 200km of new high capacity 33 kv lines; Selective upgrades on other lines; and The introduction of more advanced protection schemes on the 33kV system. This Network Development Plan is being introduced in a staged fashion, with the commissioning of projects timed to coincide with capacity or security limits being reached. The new 110kV line between Kaikohe and Wiroa will provide stepped increases in capacity by being operated for the first 20 years or more of its life at 33kV thus deferring significant investment in a 110kV substation for that period of time. Construction of this critical transmission line will shift much needed capacity to the load centre of the eastern bays. 129

132 NETWORK DEVELOPMENT PLANNING Capacity issues are not as critical in the northern area and therefore capacity reinforcement where it is found necessary is planned for the latter part of the 10 year planning period, enabling resources to be focused in the south. The Network Development Plan for the north therefore centres on line security and involves the upgrade of existing and construction of new 33kV lines to Pukenui and Taipa, in addition to a north / south interconnection from Taipa to Kaeo. A new substation at Karikari is not exected to be required within the planning period but will support the anticipated load growth on the peninsula. Figure kV system configuration Figure kV system configuration 130

133 5.9.4 Project Time line and Costs NETWORK DEVELOPMENT PLANNING 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 70 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. MAJOR PROJECT COST ($M) kV / 110kV line Kaikohe to Wiroa 6.8 Ngawha 33kV line No Kerikeri Substation and Interconnections kV Line Upgrades (incl Waipapa #1 refurbishment) 3.8 Submarine cable to Russell and Interconnections 6 33kV Switchyard and switching station Wiroa 2.55 Waipapa #2 Line refurbishments 1.3 Pukenui 33kV Line No 1 Reconstruction 2.5 Taipa Transformer Replacements 2.5 Purerua Substation and Line Interconnections 9.18 Kaeo Substation and Interconections kV Feeder Conversions - Taheke, Russell, South Rd kv Line Taipa to Kaeo kV line Haruru to Kerikei kv Line No 2 to Pukenui kV line No 2 to Taipa kV line No 2 to Omanaia 3.7 Table 41 Major Project Implementation Timeline 131

134 NETWORK DEVELOPMENT PLANNING 5.10 Detailed Project Descriptions and Development Timeline kV Sub-transmission Line Projects (inc 110kV) PROJECT NO. DETAILS DRIVER FYE START BUDGETED COST TBC Ngawha Geothermal 33kV 2nd Line Customer K$ kV - New 110kV line Kaikohe to Wiroa, Stage 1 completion of existing project kV - New 110kV line Kaikohe to Wiroa, - Stage 2 capacity ,730 capacity , kV KER- 33kV cable out of WPA substation capacity TBC Waipapa #1 line refurbishment Capacity TBC Wiroa 33 kv switching station capacity , kV Pukenui Reconstruction Stage 1 Capacity TBC 33kV KER- 33kV cable out of KER substation - Wiroa capacity kV MOE No 1 line reconductor 7kM to Cockroach. capacity TBC 33kV Waipapa #2 Stage 1 Refurb Capacity ,287 TBC 33kV Waipapa #2 Stage 2 Refurb Capacity , kV Pukenui Reconstruction Stage 2 Capacity TBC Taipa Transformer Replacements Capacity , kV KER- Underground cable to substation from overhead line kV - PUR - Build new line from WPA substation site kV - KEO - Build new line from gun club to Kaeo site. 8.5 km capacity ,265 Capacity ,716 Capacity TBC 33kV Waipapa #2 Stage 3 Refurb Capacity TBC 33kV Taipa to Kaeo Construction Capacity , kV - KEO - Upgrade line ABS to volt 800 amp. Capacity kV KEO New 33kV cable at KEO Capacity

135 NETWORK DEVELOPMENT PLANNING PROJECT NO. DETAILS DRIVER FYE START BUDGETED COST kV KEO New 33kV cable at WPA Capacity K$ TBC 33kV Pukenui #2 Stage 1 Capacity , kV - NPL - UG cable 300mm AL Capacity TBC 33kV Taipa Interconnections Capacity , kV - HAR - new line from Kerikeri Security ,740 TBC 33kV Pukenui #2 Stage 2 Capacity ,503 TBC 33kV Taipa # 2 Stage 1 Capacity , kV - OMA - Build new line from KOE to substation site km Capacity 2019/20 4,818 TBC 33kV Taipa #2 Stage 2 Capacity ,790 TBC 33kV Pukenui #2 Stage 3 Capacity ,503 Table kV/33kV line projects TEN06130/TEN07042/ TEN08010/TEN08013/TEN08014: 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 5.8.3). 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. 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, 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 line will be constructed in two stages. Stage 1 is the first section of 10km from Kaikohe to SH1, while Stage 2 is the remaining section of the line from SH1 to Wiroa. 133

136 NETWORK DEVELOPMENT PLANNING Line easement and resource consent negotiation for Stage 2 is currently in progress by Environmental Challenge. Line survey and design is being undertaken by external consultants, and construction of Stage 1 by TECS has commenced. TBC: 33kV Waipapa #1 Refurbishment To facilitate the additional voltage support at Waipapa substation and to provide a secure high capacity link 33kV mesh system from Kaikohe, it is planned to refurbish the Waipapa #1 circuits from the location of the new Wiroa switching station, along Springbank road and State Highway 10 and into the Waipapa Substation. The utilisation of selenium conductor and 300m 2 single core underground cable, will provide a high capacity link providing future voltage support for Kaeo, Purerua and Taipa expansion work. A complete re-insulation of the 6km section of 33kV line from Wiroa Rd to Waipapa substation line will be required to ensure insulator stresses are not exceeded by the new conductor and a significant number of poles replaced to provide adequate conductor clearances and/or to provide the pole strengths required by the larger conductor. The short section of line at the end of the airport runway will be run underground to provide the regulatory Civil Aviation Authority clearances. The first 10 spans out from Waipapa substation are already of 110kV construction on 18.5m steel poles (a legacy of the original 110kV line proposal) and run in Krypton conductor. The insulation of this section of line will need to be changed to 33kV standoff insulators to support the selenium conductor and the conductor tensions adjusted according to the loading capabilities of the existing poles and 33kV clearance limits. Refurbishment is planned for 2011/12. TBC: Ngawha Geothermal High Capacity OHL #2 This is a customer driven project to provide a dedicated high capacity overhead line feed between Ngawha geothermal power station and Transpower Kaikohe. The circuit will provide significant security of supply for Ngawha, together and relieve the capacity constraints exhibited on the existing circuit to Warsnops (which is the name given to the 33kV switching station at the tee connection between the existing Ngawha power station line and the 33 kv lines supplying Waipapa and the Haruru, Moerewa and Kawakawa zone substations). Completion of this line will also allow the 33kV circuit breaker intertrip at Kaikohe GXP to be removed. Ngawha geothermal power plant is situated approximately 7km from Kaikohe GXP. The generation capacity of Ngawha is 25MW. It supplies approximately 55% of the southern network load and reduces active power infeed from national grid consequently decreasing Transpower charges to Top Energy and reducing the dependency on the national grid for power supply. It is currently connected to the 33kV sub-transmission network via a single 33kV line from Ngawha to the Worsnop Switchyard. The approximate length of the existing single circuit 33kV line from Ngawha to Worsnops is 6.3km and is built with cockroach AAC (4.9km) and jaguar ACSR (1.4km) conductors. The current carrying capacity of cockroach and jaguar conductors is 42 MVA and 32MVA at 33kV respectively. This line is constrained by the capacity of the jaguar conductor and the line loading with 25MW of generation is approximately 90% of capacity. The proposed line route for the second 33kV line from the Ngawha plant runs across country in a more or less straight line from the power station to the Kaikohe GXP. In order to reduce the easement requirement and reduce the impact on landowners the line route follows property boundaries as much as possible. The total length of proposed 33kV line is 5.45km which includes 450m of 33kV 500mm 2 aluminium cable at Ngawha and underneath SH12 to Kaikohe GXP substation. Selenium conductor has been chosen as the overhead conductor with current carrying capacity of 1014Amps (@75 C) with maximum distribution capacity of 58MVA (@33kV). This conductor type is best suited to the corrosive geothermal environment at Ngawha as it is made of a high strength aluminium-magnesium-silicon alloy which offers excellent corrosion resistance as well as having excellent electrical and sag-tension characteristics. The 33kV cable will be 500mm 2 single core aluminium XLPE insulated using two cables per phase. The cables will be buried direct except underneath SH12 where cables will be placed in ducts. 134

137 NETWORK DEVELOPMENT PLANNING Construction is planned for 2011/12. TEN08008: 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. TEN07016: 33kV Pukenui Reconstruction Stage 1 Pukenui 33kV is one of the oldest and poorest condition lines the 33kV network. This is mainly due to the large number of customers that are affected by outages on the feeder affecting the availability of the line for maintenance. Traditionally maintenance work has been combined with the Transpower 110kV grid outages held annually in Kaitiaia. It is planned to utilise a large mobile generator to provide local system supplies whilst this refurbishment work is carried out over 2013 to TEN08011: Moerewa line No 1 upgrade. Top Energy plans to upgrade the size of 7km of the conductor on this line to cockroach due to the increase in load from the substations connected. This is planned for TBC: 33kV Waipapa #2 Stage 1,2 & 3 Refurbishment To compliment the additional voltage support at Waipapa substation and to provide a secure high capacity n-1 link 33kV mesh system from Kaikohe, it is planned to refurbish the Waipapa #2 circuit between Kaikohe and Wiroa Substation. The utilisation of selenium conductor and 300m 2 single core underground cable, will facilitate a secondary high capacity link providing future voltage support for Kerikeri, Haruru, Russell and Kawakawa from TEN08015: 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. TEN07035/TEN08018/TEN08019: 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 8.5 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. TBC: Build new 33kV line from Kaeo Substation to Taipa. 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 12km is planned to be built from the Kaeo substation site to the existing Taipa Substation. This will provide N-1 security of supply over both Taipa and Kaeo Substations from TEN08016: New 33kV line from Haruru Line to Kerikeri Substation Haruru Substation is currently being fed by Kawakawa#1 and Kawakawa#2 33kV lines. The Kawakawa#1 line also feeds the Moerewa and Kawakawa substation. If either of the 33kV lines is out of service, the other line is not capable of supplying the predicted load of all three substations. The current supply arrangement would not allow any maintenance work on either of the 33kV lines. The new line linking the Haruru line to Kerikeri Substation is planned to improve the security of supply to 135

138 NETWORK DEVELOPMENT PLANNING the Haruru substation in year 2015/16. The new 33kV line will allow one of the 33kV lines supplying the Haruru substation to be taken out of service and will also create a robust sub-transmission ring in the south east area. A new underground cable installation at Waipapa to the proposed Kaeo substation line (TEN07036 and TEN07037 respectively) and an upgrade of the existing ABS to 33kV 800 amps (TEN 07038) are planned in the year 2017/2018 as a part of this project. TBC: 33kV Pukenui #2 To compliment the refurbished Pukenui #1 and to facilitate the provision of meshing between Taipa, Kaitaia, Okahu Rd, NPL and Pukenui, a second feeder is planned for construction starting in The feeder has a number of route possibilities including providing a third feed to NPL. TEN07015: NPL 33kV Cable and new line into Substation. The NPL substation is fed by a double circuit 33kV line from Transpower Kaitaia which has tap-offs into Okahu Rd substation. The line construction is such that some repair and maintenance work cannot be performed on one circuit without taking the other circuit out of service. Thus, while a single fault may not lead to an immediate loss of supply there will be an outage when the repair is executed, or when routine maintenance is required. To improve the security and provide alternate supply to the NPL and Okahu substations, the plan is to build a new line from the existing Pukenui 33kV line to the NPL substation in the year 2018/19. TEN07077: 33kV TPA #2 To improve security of supply to Taipa substation, a second 33kV line is planned to be built from the Kaitaia GXP to the substation in the year 2019/2020. The route selection will provide a T connection potential for the future line to the Karikari Substation. The second 33kV transmission circuit is planned to tap off the existing Pukenui 33kV line with a new low visual impact, ground mounted switching station at Awanui. The circuit will continue around the east coast to Taipa to provide alternate supply to the Taipa substation. This project is planned to be completed in a two year time period. TEN08012: Moerewa substation upgrade. Top Energy plans to upgrade the substation to a two transformer site in 2012/13. This will release the mobile substation and provide permanent n-1 transformer security. TEN08019: Build new 33kV line from Waipapa substation to Purerua substation site. Top Energy has proposed a new substation in the Purerua area to improve the network capacity and the power quality in the area. The new line of approximately 8.5 km is planned to be built from the Waipapa substation to the new proposed substation site commencing in the year 2019/20. The completed line will connect the proposed substation site to the existing 33kV network via Waipapa substation. TEN08020: New 33kV line to Omanaia substation. The second 33kV transmission circuit is planned to be built to the Omanaia substation due to load increase going above level 1 of security of supply at the Omanaia substation in the year 2020/ /11kV Substations 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. 136

139 b) Security NETWORK DEVELOPMENT PLANNING 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 d) Substation Projects PROJECT NO. DETAILS DRIVER FYE START BUDGETED COST TBC 110KV Wiroa Substation Land Purchase and Consent K$ Capacity TBC 33kV Wiroa Switching Station Capacity ,000 Table 43 Wiroa substation projects TBC 110kV Land Purchase at Wiroa The project is to identify, procure and designate a suitable parcel of land on which to establish the Wiroa 110V and 33kV site. The site itself is highly strategic and the optimal location will present ease of access to Kaikohe, Waipapa, Kerikeri and Mt Pokaka circuits. The land purchase and designation is planned for TBC 110kV Land Purchase at Wiroa The project is to establish a 33kV switching station on the chosen and designated site as detailed above. The site itself is highly strategic and will provide inter-mesh links between Kaikohe, Waipapa, Kerikeri and Mt Pokaka circuits. The project is to commence in Okahu Substation. 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. a) 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. b) Capacity The existing two 11.5 MVA transformers are adequate to supply the forecasted load for the planning period. c) 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. 137

140 NETWORK DEVELOPMENT PLANNING d) Substation Projects PROJECT NO. DETAILS DRIVER START YEAR BUDGETED COST K$ TBC Ground Fault Neutraliser Installation Reliability SUB - OKH - Install new Security Cameras Reliability SUB - OKH - Feeder metering, install new SEL 734 x 6 into existing feeder panels Reliability 2019/20 50 Table 44 Okahu Rd substation projects TBC: ground Fault Neutraliser Installation. Subject to a successful trial in Waipapa zone substation, it is planned to install the Swedish neutral ground fault neutraliser system at Okahu Road substation. Based upon the long used Peterson arc suppression coil, the system is designed to reduce the likelihood of inadvertent contact, electric shock and localised fires associate with single phase to earth faults by detecting the fault and injecting an equal but opposite current into the faulty conductor. It is seen as a significant step forward in operational safety on the Top Energy network. TEN06068: New security camera. The project is to install two security cameras in the substation building to give added safety and security in the year TEN07010: 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 2019/ 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. 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 138

141 NETWORK DEVELOPMENT PLANNING 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 TEN06070 SUB - PKN - Install new Security Cameras Reliability TBC Ground Fault Neutraliser Installation Reliability Table 45 Pukenui substation projects TEN06070: New security camera. The project to install two security cameras in the substation building to give added security in the year 2011/12. TBC: Ground Fault Neutraliser Installation. Subject to a successful trial in Waipapa zone substation it is planned to install the Swedish neutral ground fault neutraliser system. Based upon the long used Peterson arc suppression coil, the system is designed to reduce the likelihood of inadvertent contact, electric shock and localised fires associate with single phase to earth faults by detecting the fault and injecting an equal but opposite current into the faulty conductor. It is seen as a significant step forward in operational safety on the Top Energy network 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 annual growth rate at Taipa is higher than Top Energy s annual average growth rate. a) 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. b) 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. c) 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. The location of the substation is such that there is very limited opportunity to improve interconnection at 11kV. Therefore, Top Energy is planning to install a second 33kV circuit as discussed in sub-transmission section and is also planning to install 2 x 11.5/23 MVA transformers in year 2015 to meet the forecast demand and the security of supply requirements. The substation has much, but not all, of the configuration for two transformer operation already in place. In the event of a 33kV line outage, most faults can be expected to be repaired in approximately 3 hours, and in the event of a transformer fault the mobile substation could be moved to site within K$ 139

142 NETWORK DEVELOPMENT PLANNING approximately 10 hours. The interconnection with Kaeo and the second circuit from Kaitaia will provide N-1 line security in 2017 d) Substation Projects PROJECT NO. DETAILS DRIVER START YEAR BUDGETED COST TEN06069 SUB - TPA - Install new Security Cameras Reliability K$ TEN07109 TEN07014 SUB - TPA - T1 and T2 new Protection panels, SEL 387E, Reg D, SUB - TPA - Lower transformer to ground level and bunding Reliability Compliance TEN06076 SUB - TPA - Purchase new 33//11kV 11.5/23 MVA x 2 transformers Capacity / Security ,000 TBC Ground Fault Neutraliser Installation Reliability TEN07012 SUB - TPA - Feeder protection upgrade, new SEL 351S x 4,SEL 2032 and GPS clock on CB panel. Reliability Table 46 Taipa substation projects TEN06069: New security camera. The project is to install two security cameras in the substation building to give added security in the year 2011/12. TEN07019: New transformer protection relays. The project to install two new transformer protection relays in the year 2011/12. TEN07104: New transformer bunding. To improve earthquake resistance and to provide oil containment for any oil spillage from zone substation transformers, it is planned to lower the transformer from its structure for bunding in the year 2013/14 before relocating the transformer to Omanaia substation as planned. TEN06076: New transformers. The project is to purchase and install two new 11.5/23 MVA transformers in the year 2014/15. The removed transformer will be relocated to Omanaia substation as planned. TBC: Ground Fault Neutraliser Installation. Subject to a successful trial in Waipapa zone substation it is planned to install the Swedish neutral ground fault neutraliser system. Based upon the long used Peterson arc suppression coil, the system is designed to reduce the likelihood of inadvertent contact, electric shock and localised fires associate with single phase to earth faults by detecting the fault and injecting an equal but opposite current into the faulty conductor. It is seen as a significant step forward in operational safety on the Top Energy network. TEN07012: New feeder protection relays. The project to install four new SEL 351S protection relays to give better metering and fault information for planning and fault analyse in the year 2016/

143 Northern Pulp Substation (NPL) NETWORK DEVELOPMENT PLANNING 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 increasing 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 TEN07017 SUB - NPL - Line protection for new feeder,pukenui tap off using 33 NOVA and SEL 351R k$ Reliability / Security TEN06071 SUB - NPL - Install Security Cameras Reliability TBC Ground Fault Neutraliser Installation Reliability TEN07011 SUB - NPL - Feeder metering, install new SEL 734 x 6 into New panel. Reliability 2017/18 60 TEN07068 SUB - NPL - New 33kV CB for new line. Security Table 47 NPL substation projects TEN07017: New line protection relays. The project to install one new SEL 351R protection relays to give directional protection on the line in the year This is part of a major protection upgrade plan for the network for TEN06071: New security camera. 141

144 NETWORK DEVELOPMENT PLANNING The project is to install two security cameras in the substation building to give added security in the year 2011/12. TBC: Ground Fault Neutraliser Installation. Subject to a successful trial in Waipapa zone substation it is planned to install the Swedish Neutral Ground Fault Neutraliser system. Based upon the long used Peterson Arc Suppression Coil, the system is designed to reduce the likelihood of inadvertent contact, electric shock and localised fires associate with single phase to earth faults by detecting the fault and injecting an equal but opposite current into the faulty conductor. It is seen as a significant step forward in operational safety on the Top Energy network. TEN07011: New feeder protection relays. The project to install six new SEL 734 protection relays to give better metering and fault information for planning and fault analysis in the year 2017/18. TEN07068: New line recloser for new line from Pukenui line. The project to install a new NOVA recloser to connect the new line built from the existing Pukenui line to the NPL substation to give better security of supply in the year 2018/ 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 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 TBC Ground Fault Neutraliser Installation Reliability TEN06062 SUB - KHE - Install new Security cameras Reliability K$ TEN07020 TEN07021 TEN07108 Table 48 SUB - KHE - Feeder protection upgrade, new SEL 351S x 7 in new boxes on CBS, SEL2032.GPS clock. SUB - KHE - transformer Protection upgrade, new Panels x 2, SEL 387E, Reg D. SUB - KHE - Lower transformers to ground level and bunding Kaikohe substation projects Reliability Reliability Compliance

145 NETWORK DEVELOPMENT PLANNING TBC: Ground Fault Neutraliser Installation. Subject to a successful trial in Waipapa zone substation it is planned to install the Swedish neutral ground fault neutraliser system. Based upon the long used Peterson arc suppression coil, the system is designed to reduce the likelihood of inadvertent contact, electric shock and localised fires associate with single phase to earth faults by detecting the fault and injecting an equal but opposite current into the faulty conductor. It is seen as a significant step forward in operational safety on the Top Energy network. TEN06062: New security camera. The project to install two security cameras in the substation building to give added security in the year TEN07020: New feeder protection relays. The project to install seven new SEL 351S protection relays to give better metering and fault information for planning and fault analyse in the year TEN07021: New transformer protection relays. The project to install two new transformer protection relays in the year TEN07108: New transformer bunding. To improve earthquake resistance and to provide oil containment for any oil spillage from zone substation transformers, it is planned to lower the transformers from its structure for bunding in the year Kawakawa Substation 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 TBC Ground Fault Neutraliser Installation Reliability TEN06063 SUB - KWA - Install new Security Cameras Reliability K$ TEN07023 TEN07048 SUB - KWA - T1 protection upgrade, new SEL 387E, Reg D, 1 A NCT, GPS Clock, SUB - KWA - Feeder protection upgrade, new SEL 351S x 4 in new boxes on CBS, SEL2032, GPS clock. Reliability / Security Reliability

146 NETWORK DEVELOPMENT PLANNING PROJECT NO. DETAILS DRIVER START YEAR BUDGETED COST TEN08033 SUB - KWA - Lower transformers to ground level and bunding K$ Compliance Table 49 Kawakawa substation projects TBC: Ground Fault Neutraliser Installation. Subject to a successful trial in Waipapa zone substation it is planned to install the Swedish neutral ground fault neutraliser system. Based upon the long used Peterson arc suppression coil, the system is designed to reduce the likelihood of inadvertent contact, electric shock and localised fires associate with single phase to earth faults by detecting the fault and injecting an equal but opposite current into the faulty conductor. It is seen as a significant step forward in operational safety on the Top Energy network. TEN06063: New security camera. The project is to install two security cameras in the substation building to give added security in the year 2011/12. TEN07023: New transformer protection relays. The project is to install two new protection relays to give add security in the year 2017/18. TEN07048: New feeder protection relays. The project to install 4 new SEL 351S protection relays to give better metering and fault information for planning and fault analyse in the year 2017/18. TEN08033: New transformer bunding. To improve earthquake resistance and to provide oil containment for any oil spillage from zone substation transformers, it is planned to lower the transformers from its structure for bunding in the year 2017/ 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. 144

147 NETWORK DEVELOPMENT PLANNING d) Substation Projects PROJECT NO. DETAILS DRIVER START YEAR BUDGETED COST TEN06064 SUB - MOE - Install new Security Cameras Reliability TBC Ground Fault Neutraliser Installation Reliability K$ TEN06138 TEN07024 TEN07107 SUB - MOE - New Circuit Breaker 62 NOVA on new pad SUB - MOE - Feeder protection upgrade, new SEL 351R x 4, SEL SUB - MOE - Lower transformers to ground level and bunding Security Reliability Compliance Table 50 Moerewa substation projects TEN06064: New security camera. The project is to install two security cameras in the substation building to give added security in the year TBC: Ground Fault Neutraliser Installation. Subject to a successful trial in Waipapa zone substation it is planned to install the Swedish neutral ground fault neutraliser system. Based upon the long used Peterson arc suppression coil, the system is designed to reduce the likelihood of inadvertent contact, electric shock and localised fires associate with single phase to earth faults by detecting the fault and injecting an equal but opposite current into the faulty conductor. It is seen as a significant step forward in operational safety on the Top Energy network. TEN06138: Replacement 33kV recloser CB 42. The project to install one replacement NOVA recloser due to condition in the year TEN07024: New feeder protection relays. The project to install 4 new SEL 351R protection relays to give better metering and fault information for planning and fault analyse in the year 2013 TEN07107: New transformer bunding T1. 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 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. b) Capacity The substation has two transformers. each rated at 23MVA, which are adequate to supply the forecasted load for the planning period. 145

148 c) Security NETWORK DEVELOPMENT PLANNING 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 Tbc Ground fault neutraliser installation Reliability Ten06067 Sub - har - install new security cameras Reliability Tbc Russell 22kv submarine cable feeder Security / reliability ,000 Table 51 Haruru Falls substation projects TBC: Ground Fault Neutraliser Installation. Subject to a successful trial in Waipapa zone substation it is planned to install the Swedish neutral ground fault neutraliser system. Based upon the long used Peterson arc suppression coil, the system is designed to reduce the likelihood of inadvertent contact, electric shock and localised fires associated with single phase to earth faults by detecting the fault and injecting an equal but opposite current into the faulty conductor. It is seen as a significant step forward in operational safety on the Top Energy network. TEN06067: New security camera. The project is to install two security cameras in the substation building to give added security in the year TBC: Russell township 22kV submarine cable feeder. This project is planned to deliver security of supply to Russell township in The township currently is situated on the end of a long rural 11kV feeder and in conjunction with a proposed 22kV upgrade from Kawakawa substation, the submarine cable will provide a N-1 supply over the township for the first time 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 K$ 146

149 NETWORK DEVELOPMENT PLANNING The substation has two transformers, a single split 33kV bus and 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. 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. 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 TBC TEN06014 TBC SUB- WPA New feeder breaker for Waipapa Business centre SUB - WPA - 4x 750kVAr switched capacitor banks SUB - WPA 33kV Busbar and protection upgrade K$ Reliability Voltage Compliance Reliability TEN06065 SUB - WPA - Install new Security Cameras Reliability TEN07106 TEN07085 SUB - WPA - Lower transformers to ground level and bunding SUB - WPA - New Ripple injection plant Waipapa. Compliance Capacity Table 52 Waipapa substation projects TBC: New feeder breaker for the Waipapa Business centre. The project is to install a dedicated 11kV circuit breaker for the new 11kV underground cable feed to the Waiapa Business Centre. Waiapa is rapidly expanding to become the major out of town retail and commercial centre of the Bay of Islands. The expansion is now attracting large customers such as the Warehouse, Harvey Norman and Dick Smith. A new school is also planned in the vicinity within the next three years. TEN06014: New 11kV switched capacitors. The project is to install new switched capacitors to reduce the losses on the 33kV line and substation in the year TBC: New 33kV busbar and feeder protection upgrade. The project to install new SEL 351SR protection relays to give better metering and fault information for planning and fault analysis in the year This is being carried out as part of the network protection upgrade programme. TEN06065: New security camera. The project is to install two security cameras in the substation building to give added security in the year TEN07016: 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

150 NETWORK DEVELOPMENT PLANNING TEN07058: New ripple injection plant. To improve reliability of load control in the southern area if Ngawha goes in to Island mode we plan to install a third injection site in the year Omanaia Substation 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 TEN07032 SUB - OMA - Feeder protection upgrade, SEL 351R x 2, SEL 2032, GPS clock. K$ Reliability TEN06066 SUB - OMA - Install new Security Cameras Reliability TEN06072 TEN07033 SUB - OMA - Sub tap in before boosters for alternate feed from Taheke feeder (Kaikohe substation). SUB - OMA - Transformer T1 Protection upgrade, SEL 387E, New NCT 1A, Existing Circuit Breakers ok. Security Reliability / Security TEN06081 SUB - OMA - install 5/6.25MVA ex TPA Capacity TBC Ground Fault Neutraliser Installation Reliability Table 53 Omania substation projects TEN07032: New feeder protection relays. The project to install 4 new SEL 351SR protection relays to give better metering and fault information for planning and fault analyse in the year 2010/11 TEN06066: New security camera. 148

151 NETWORK DEVELOPMENT PLANNING The project is to install two security cameras in the substation building to give added security in the year 2011/12TEN06135: New 33kV line protection. TEN06072: New back up from Taheke feeder connection point to substation The project to install a new connection point on the Rawene feeder to the Omanaia substation to let the back feed from Kaikohe to be feed in to the substation before the voltage regulators to give a higher ability to back feed the Omanaia feeders. TEN06081: 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 over the transformers in 2016 and over the entire substation following the 33kV Omaniaia #2 feeder construction in TBC: Ground Fault Neutraliser Installation. Subject to a successful trial in Waipapa zone substation it is planned to install the Swedish neutral ground fault neutraliser system. Based upon the long used Peterson arc suppression coil, the system is designed to reduce the likelihood of inadvertent contact, electric shock and localised fires associate with single phase to earth faults by detecting the fault and injecting an equal but opposite current into the faulty conductor. It is seen as a significant step forward in operational safety on the Top Energy network Proposed Kaeo Substation Planning studies have shown that it will be necessary to establish a new zone substation in the Kaeo region with a new 33kV/11kV 11.5MVA transformer during the present planning period. This reflects recent high load growth in the region, security and capacity issues at the Waipapa substation. Top Energy already owns land on Martin Road, Kaeo and has obtained the resource consent for the new proposed substation. The substation is planned to be commissioned in the year 2017/18. 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. 149

152 NETWORK DEVELOPMENT PLANNING d) Substation Projects PROJECT NO. DETAILS DRIVER START YEAR BUDGETED COST TEN07002 SUB - KAEO - Fencing, Road access, Planting Capacity K$ TEN07071 SUB - KAEO - New substation at Kaeo with 1 x 11.5MVA transformer. Capacity 2017/18 3,600 TEN x new 11kV feeders from S/S Capacity TEN07003 SUB - KAEO - Substation Construction and change over Capacity ,350 Table 54 Proposed Kaeo substation projects TEN07002: Fencing, access and planting Site establishment and naturalisation works on this Greenfield site in Kaeo. TEN07071: New 11.5MVA transformer Installation works for the transformer. TEN07003: Substation construction and change over Construction, network integration and commissioning works for the 33kV and 11kV systems. TEN07045: 5x new 11kV feeders from S/S Construction, network integration and commissioning works for the 11kV substation feeders Proposed Kerikeri Substation Planning studies have shown that it will be necessary to establish a new zone substation in the Kerikeri region with two new 33kV/11kV 11.5/23 MVA transformer during the present planning period. This reflects recent high load growth in the region, security and capacity issues at the Waipapa substation. 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. 150

153 NETWORK DEVELOPMENT PLANNING d) Substation Projects PROJECT NO. DETAILS DRIVER START YEAR BUDGETED COST K$ TEN09003 SUB KER Civil works Capacity TEN09004 SUB KER Substation building Capacity TEN09005 SUB KER 12kV switchboard Capacity TEN09006 SUB KER 33kV switchboard Capacity TEN09007 SUB KER 11kV cables to transformer Capacity TEN09008 SUB KER 33kV SCADA and DC systems Capacity TEN09009 SUB KER T1 transformer 11.5/23 MVA Capacity ,000 TEN09009 SUB KER T2 transformer 11.5/23 MVA Capacity ,000 TBC 2km 11kV 185mm2 3c from Substation to 3 feeders Capacity ,000 TBC SUB - New Kerikeri ZS - Construction of KER No 2 33kV line from Wiroa to Kerikeri Sub 4km Capacity TBC Ground Fault Neutraliser Installation Reliability Table 55 TEN09003: Civil Works Proposed Kerikeri substation projects Site establishment and naturalisation works on this Greenfield site in Kerikeri. TEN09004: Substation Building. The building is planned to be designed to blend as inconspicuously as possible into its surroundings by utilising materials similar to domestic residence construction. TEN07005, 6, 7, and 8: Substation construction and change over Construction, network integration and commissioning works for the 33kV and 11kV systems. TEN07009: Two new 11.5/23MVA transformers Installation works for the transformers. TBC: 4x new 11kV feeders from S/S, and 1 new 33kV feeder from the substation Construction, network integration and commissioning works for the 11kV and 33kV substation feeders TBC: Ground Fault Neutraliser Installation. Subject to a successful trial in Waipapa zone substation it is planned to install the Swedish neutral ground fault neutraliser system. Based upon the long used Peterson arc suppression coil, the system is designed to reduce the likelihood of inadvertent contact, electric shock and localised fires associate with single phase to earth faults by detecting the fault and injecting an equal but opposite current into the faulty conductor. It is seen as a significant step forward in operational safety on the Top Energy network. 151

154 NETWORK DEVELOPMENT PLANNING 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. d) Substation Projects PROJECT NO. DETAILS DRIVER START YEAR BUDGETED COST K$ TEN00910 SUB PUR Easements - LAND Capacity TEN00911 SUB PUR Civil works Capacity TEN00913 SUB PUR Substation building Capacity TEN00914 SUB PUR 12kV switch board Capacity TEN00915 SUB PUR 33kV switch board Capacity TEN00916 SUB PUR 11kV cables to transformer Capacity TEN00917 SUB PUR 33kV cables to switch gear Capacity TEN00918 SUB PUR 33kV SCADA and DC systems Capacity TBC Ground Fault Neutraliser Installation Reliability TEN00919 SUB PUR T1 transformer 11.5MVA Capacity ,000 Table 56 Proposed Purerua substation projects 152

155 NETWORK DEVELOPMENT PLANNING TEN00910: Land Purchase Site procurement, easement and designation project. TEN00911: Civil Works Site establishment and naturalisation works on this Greenfield site in Purerua TEN00913: Substation Building. The building will be designed with local prevailing conditions and requirements in mind. TEN00914, 5, 6, 7 and 8: Substation construction and change over Construction, network integration and commissioning works for the 33kV and 11kV systems. TEN00919: New 11.5/23MVA transformer Installation works for the transformer. TBC: Ground Fault Neutraliser Installation. Subject to a successful trial in Waipapa zone substation it is planned to install the Swedish neutral ground fault neutraliser system. Based upon the long used Peterson arc suppression coil, the system is designed to reduce the likelihood of inadvertent contact, electric shock and localised fires associate with single phase to earth faults by detecting the fault and injecting an equal but opposite current into the faulty conductor. It is seen as a significant step forward in operational safety on the Top Energy network Distribution Network This section covers projects on the 11kV distribution feeders including single wire earth return (SWER) lines and projects are grouped by zone substation. In 2009, the 11kV distribution feeders were modelled and investigated for any capacity, security, reliability and voltage compliance issues for the planning period. This analysis will be updated on an annual basis. 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 PROJECT NO. DETAILS DRIVER START YEAR BUDGETED COST K$ TEN06126 SWER - LINE - Te Haupua T01324 converts to 3w - Te Kao Feeder. Capacity / Voltage Compliance Table 57 Pukenui substation distribution projects TEN06126: 11/22kV line conversion Te Kau feeder The investigation has identified voltage drop issues on the Te Kao feeder, north of Pukenui. The SWER line conversion to 3 wire is planned in the year 2012/13 to mitigate these issues. 153

156 NPL Substation NETWORK DEVELOPMENT PLANNING 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. PROJECT NO. DETAILS DRIVER START YEAR BUDGETED COST K$ TEN06139 SWER - 11KV - Motuti convert 6.35kV to 11kV,T South Rd Fdr. Capacity TEN08035 SWER - TX - Snelgar's Rd upgrade Tx T Oxford Rd Fdr. Capacity TEN06122 SWER - 11kV - Duncan's Rd convert 6.35 kv to 11kV,T Oxford Rd Fdr. Capacity TEN06107 SWER - 11kV - Duncans Rd 6.35kV to 11kV-Oxford St Fdr. Capacity TEN07114 SWER - Isolating TX T Whangape change - South Rd Fdr. TEN06117 SWER - Line - Mangatoetoe upgrade Tx T Oxford Rd Fdr. Capacity Capacity EN07076 DIST - 22kV South Rd feeder to 22kV Stage 1. Voltage Compliance TEN06151 DIST - Load transfer capability NPL-OKH Capacity Table 58 Okahu Rd substation distribution projects TEN06139: 6.35kV line voltage upgrade. It is identified that Motuti SWER will have voltage drop issues in the year The line upgrade is planned for in the year 2016 to mitigate this issue. TEN08035: SWER transformer upgrade. It is identified that Snelgr s Rd SWER will have loading issues in the year The transformer upgrade is planned for in the year 2015 to mitigate this issue. TEN06122: 6.35kV line voltage upgrade. It is identified that Duncan s Rd SWER will have voltage drop issues in the year The line upgrade is planned for in the year 2016 to mitigate this issue. TEN06107: 6.35kV line voltage upgrade. It is identified that Whangape SWER will have voltage drop issues in the year The line upgrade is planned for in the year 2016 to mitigate this issue. TEN07114: SWER transformer upgrade. It is identified that Whangape SWER will have loading issues in the year 2015/16. The transformer upgrade to 100kVA is planned for in the year 2015/16 to mitigate this issue. 154

157 NETWORK DEVELOPMENT PLANNING TEN06117: SWER transformer upgrade. It is identified that Mangatoetoe SWER will have loading issues in the year The transformer upgrade to 100kVA is planned for in the year 2016 to mitigate this issue. TEN07076: 11/22kV line conversion south Rd feeder. 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 TEN06151: 11kV load transfer capability NPL- OKH. The ability to shift load between the NPL and Okahu Rd substations is minimal. It is planned to improve the load transfer capability between the Okahu Rd and NPL substation in the year 2020 and therefore security by conductor upgrades and installation of remote controlled equipment 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 TEN06119 TEN06157 SWER - 11kV - Parapara convert kv to 11kV,T Tokerau Fdr. DIST - Load transfer capability TPA-WPA - switches, etc K$ Capacity Security TEN06149 DIST - Tokerau Feeder - install 14km Voltage Compliance Table 59 Taipa substation distribution projects TEN06119: 6.35kV line voltage upgrade. It is identified that Parapara SWER will have voltage drop issues in the year The line upgrade to 11kV is planned for in the year 2015 to mitigate this issue. TEN06157: 11kV load transfer capability TPA- WPA. The ability to shift load between the Taipa and Waipapa substations is minimal. It is planned to improve the load transfer capability between the Taipa and Waipapa substation in the year 2020 and therefore security by conductor upgrades and installation of remote controlled equipment. TEN06149: Voltage regulator on Tokerau feeder. 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 Kaikohe Substation 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. 155

158 NETWORK DEVELOPMENT PLANNING PROJECT NO. DETAILS DRIVER START YEAR BUDGETED COST TEN06112 SWER - 11kV Tutekehua / Omahuta 6.35kV to 11kV, T01300 to 200kVA -Rangiahua Fdr. K$ Capacity 2015/ TEN06110 SWER - TX - Hapanga Rd upgrade Tx T Horeke Fdr. TEN06108 SWER - TX - Te Tio Rd upgrade Tx T Rangiahua Fdr. Capacity 2015/ Capacity 2015/ TEN06113 SWER - TX - Creamery Rd upgrade Tx T01277 to 100kVA - Horeke Fdr. Capacity 2015/ TEN06116 SWER - 3 Wire - Renwick Rd B103 Rebuild of 3 wire, Isolating Tx T Taheke Fdr. Capacity 2015/ TEN07086 DIST - 22kV Taheke feeder to 22kV Stage 1 Voltage Compliance / Security 2018/ TEN06156 TEN06154 DIST - Load transfer capability KHE-MOE switched capacitors Ohaeawai Feeder + Remote Control Sw's DIST - Load transfer capability OMA-KHE - switches, etc on Taheke / Horeke / Rawene fdrs Remote Control ABS 423 or 330 Security 2020/21 90 Security 2020/ Table 60 Kaikohe substation distribution projects TEN06112: SWER transformer upgrade. It is identified that Tutekehua / Omahuta SWER will have loading issues in the year 2015/16. The transformer upgrade to 200kVA is planned for in the year 2015/16 to mitigate this issue. TEN06110: SWER transformer upgrade. It is identified that Hapanga SWER will have loading issues in the year 2015/16. The transformer upgrade to 200kVA is planned for in the year 2015/16 to mitigate this issue. TEN06108: SWER transformer upgrade. It is identified that Te Tio Rd SWER will have loading issues in the year 2015/16. The transformer upgrade to 200kVA is planned for in the year 2015/16 to mitigate this issue. TEN06113: SWER transformer upgrade. It is identified that Creamery Rd SWER will have loading issues in the year 2015/16. The transformer upgrade to 100kVA is planned for in the year 2015/16 to mitigate this issue. TEN06116: 11kV line 1phase to 3 phases line conversion. It is identified that Renwick SWER will have voltage drop issues on line in 2015/16. The line will be upgraded to three phases and in size in the year 2015/16 to mitigate this issue. TEN07086: 11/22kV line conversion Taheke feeder. 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 2018/19. TEN06156: 11kV load transfer capability KHE- MOE. The ability to shift load between the Kaikohe and Moerewa substations is minimal. It is planned to improve the load transfer capability between the Kaikohe and Moerewa substation in the year 2020/21 and therefore security by conductor upgrades and installation of remote controlled equipment. 156

159 NETWORK DEVELOPMENT PLANNING TEN06154: 11kV load transfer capability KHE- OMA. The ability to shift load between the Kaikohe and Omanaia substations is minimal. It is planned to improve the load transfer capability between the Kaikohe and Omanaia substation in the year 2020/21 and therefore security by conductor upgrades and installation of remote controlled equipment 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 K$ TEN07099 DIST - Kawakawa - upgrade all 50 mm Cu leaving substation to Bee conductor. 2 kms, Capacity / Security TEN07105 TEN05032 SUB - KWA - Install new feeder to existing 33kV line. Take load off Russell feeder. Move some load off Opua feeder. SWER - TX - Rawhiti SWER replacement Isolating Tx T Russell Fdr. Capacity Capacity 2015/ TEN07078 DIST - 22kV Russell feeder to 22kV. Stage1. Voltage Compliance 2017/ TEN06152 DIST - Load transfer capability KWA- HAR - switches, etc TEN06153 DIST - Load transfer capability KWA- MOE - switches, etc Security 2020/ Security 2020/ Table 61 Kawakawa substation distribution projects TEN07099: 11kV line conductor upgrade. It is identified that all four Kawakawa feeders will have voltage drop issues on the first section of 50mm Cu just out of the substation in the year 2010/11. The sections of lines will all be upgraded to Bee. This is planned for in the year 2012 to mitigate this issue. TEN07105: New 11kV feeder. It is identified that using the existing 33kV line as the start of the Russell feeder will assist in the first stage 22kV conversion project. This line will be connected to the spare feeder breaker and to the Russell feeder by end of existing 33kV line. The existing Russell feeder to this point will then become the Opua feeder. The existing Opua feeder will be the new feeder feeding up to start of Waikare road. This is planned for in the year TEN05032: 11kV line 1phase to 3 phases line conversion. It is identified that Rawhiti SWER will have voltage drop issues on line in 2015/16. The line will be upgraded to three phases and in size in the year 2015/16 to mitigate this issue. TEN07078: 11/22kV line conversion Russell feeder. 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 2014/15. TEN06152: 11kV load transfer capability KWA- HAR. The ability to shift load between the Kawakawa and Haruru substations is minimal. It is planned to improve the load transfer capability between the Kawakawa and Haruru substation in the year 2020/21 and therefore security by conductor upgrades and installation of remote controlled equipment. 157

160 NETWORK DEVELOPMENT PLANNING TEN06153: 11kV load transfer capability KWA- MOE. The ability to shift load between the Kawakawa and Moerewa substations is minimal. It is planned to improve the load transfer capability between the Kawakawa and Moerewa substation in the year 2020/21 and therefore security by conductor upgrades and installation of remote controlled equipment 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. PROJECT NO. DETAILS DRIVER START YEAR BUDGETED COST TEN07120 SWER Capacity: MOE, Whangae Rd, McIntyre Rd convert to 11kV 100kVA T03897 K$ Capacity 2015/ Table 62 Moerewa substation distribution projects TEN07120: SWER transformer upgrade. It is identified that Whangae Rd SWER will have loading issues in the year 2015/16. The transformer upgrade to 100kVA is planned for in the year 2015/16 to mitigate this issue 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 TEN07018 DIST - 22KV Ti Bay Rd feeder to Ti Bay. 5.1 km Capacity 2012/13 2,025 K$ TEN08037 TEN06104 DIST - Load transfer capability HAR- KWA - switches, etc DIST - 22kV - new 22kV line HAR to Inlet Rd via forest Security 2020/ Security 2021/ Table 63 Haruru Falls substation distribution projects TEN07018, TEN06056, TEN06080: New 22kV feeder to Russell The capacity driven projects mentioned are primarily driven by the need to shift the Russell feeder load from Kawakawa substation onto Haruru substation via the existing 33kV line and new submarine cable planned for 2012/14. This means the building of a new feeder for Haruru substation to Paihia. Resource consent to undertake the submarine work was obtained in 2006/07. TEN08037: 11kV load transfer capability HAR - KWA. The ability to shift load between the Haruru and kawakawa substations is minimal. It is planned to improve the load transfer capability between the Haruru and Kawakawa substation in the year 2020/21 and therefore security by conductor upgrades and installation of remote controlled equipment. TEN06104: New 22kV feeder. A new 22kV feeder is planned to be built to Inlet Road in conjunction with Far North District Council s plans for strategic roading improvements to the area. This is budgeted in the years from 2013 to

161 NETWORK DEVELOPMENT PLANNING and would increase the transfer load capacity between Haruru and Waipapa substations and provide an alternate supply to the Kerikeri Township 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 TEN09001 TEN08037 DIST - New Feeder for Waipapa Business Centre- 11kV 300 mm2 Al Cable DIST- Purerua feeder- 200 Amp Voltage regulators at 5.11 Km K$ Capacity Supply quality TEN08039 DIST- Riverview feeder- 200 Amp Voltage regulators at 8.0 Km Supply quality TEN06094 TEN06097 SWER - TX Kahoe / Taratara upgrade Tx T01285 to 200kVA - Totara Nth Fdr. SWER - 11kV - Te Ngaire / Wainui 6.35kV to 11kV, Isolating Tx T00004 _ China clay Fdr. Capacity Capacity 2015/ TEN06158 DIST - Load transfer capability WPA - KHE - switches, etc Security 2020/ Table 64 Waipapa substation distribution projects TEN09001: New feeder for the Waipapa Business centre. The project is to install a dedicated 11kV circuit for the new 11kV underground cable feed to the Waiapa Business Centre. Waiapa is rapidly expanding to become the major out of town retail and commercial centre of the Bay of Islands. The expansion is now attracting large customers such as the Warehouse, Harvey Norman and Dick Smith. A new school is also planned in the vicinity within the next three years. It is identified that Aerodrome Rd will have loading issues in the year 2010/11. The installation of a new feeder to the Waipapa business centre will take load off the existing Aerodrome Rd feeder in the year 2011 to mitigate this issue. TEN08037: New voltage regulator installs. It is identified that Purerua feeder will have loading issues in the year 2010/11. The installation of a new three by 200 Amp Voltage regulator site located 5.11 km from the substation is planned for the year 2010/11. TEN08039: New voltage regulator installs. It is identified that Riverview feeder will have loading issues in the year 2010/11. The installation of a new three by 200 Amp Voltage regulator site located 8.0 km from the substation is planned for the year 2010/11. TEN06094: SWER transformer upgrade. It is identified that Hapanga SWER will have loading issues in the year 2015/16. The transformer upgrade to 200kVA is planned for in the year 2015/16 to mitigate this issue. TEN06097: 6.35kV line voltage upgrade. It is identified that Te Ngaire /Wainui SWER will have voltage drop issues in the year 2015/16. The line upgrade to 11kV is planned for in the year 2015/16 to mitigate this issue. 159

162 NETWORK DEVELOPMENT PLANNING TEN06158: 11kV load transfer capability WPA - KHE. The ability to shift load between the Waipapa and Kaikohe substations is minimal. It is planned to improve the load transfer capability between the Kaikohe and Waipapa substation in the year 2020/21 and therefore security by conductor upgrades and installation of remote controlled equipment Omanaia Substation 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 TEN06085 SWER - TX - Wharekawa Rd Oue Tx upgrade, Isolating T Opononi Fdr K$ Capacity 2015/ TEN06084 SWER - TX - Waima Valley Rd Tx T09038 Upgrade - Rawene Fdr. Capacity 2015/ Table 65 Omanaia substation distribution projects TEN06085: SWER transformer upgrade. It is identified that Wharekawa Rd SWER will have loading issues in the year 2015/16. The transformer upgrade to 200kVA is planned for in the year 2015/16 to mitigate this issue. TEN06084: SWER transformer upgrade. It is identified that Waima valley SWER will have loading issues in the year 2015/16. The transformer upgrade to 200kVA is planned for in the year 2015/16 to mitigate this issue Network Wide Projects This section covers general projects that affect more than just individual feeders throughout the Top Energy network. Projects on Feeders PROJECT NO. DETAILS DRIVER START YEAR BUDGETED COST TEN08040 TEN08040 TEN08040 TEN08040 DIST Existing Pole mount transformer lightning arrestor installation DIST Existing Pole mount transformer lightning arrestor installation DIST Existing Pole mount transformer lightning arrestor installation DIST Existing Pole mount transformer lightning arrestor installation K$ Reliability ,250 Reliability ,250 Reliability ,000 Reliability ,000 TBC Mobile generator Purchase Capacity ,100 Table 66 Network wide projects 160

163 NETWORK DEVELOPMENT PLANNING TEN08040: distribution transformer lightning arrestors. This project covers the installation of new lightning arrestors to existing pole mount transformers to reduce the number of transformer faults from lightning strikes in the year 2009/10. TBC: Mobile Generator Purchase. Large Mobile Generator in the region of 1.2MVA to assist with maintaining customer supplies during peak load periods whilst the Network development plan is enacted. The generator will also be used to restore supplies rapidly following major fault events Breakdown of the Capital Expenditure Budget The proposed ten year capital expenditure budget is detailed below: Figure71 Capital Expenditure Category Spend Profile 2012 to

164 NETWORK DEVELOPMENT PLANNING YEAR 1 YEAR 2 YEAR 3 YEAR 4 YEAR 5 YEAR 6 YEAR 7 YEAR 8 YEAR 9 YEAR 10 FOR YEAR ENDED Capital Expenditure: Customer Connection Capital Expenditure: System Growth Capital Expenditure: Reliability, Safety and Environment Capital Expenditure: Asset Replacement and Renewal Capital Expenditure: Asset Relocations Subtotal - Capital Expenditure on asset management Capital Expenditure on Non- System Fixed Assets Total direct expenditure on distribution network 1,000,000 1,200,000 1,500,000 1,500,000 1,500,000 1,500,000 1,500,000 1,500,000 1,500,000 1,500,000 6,686,006 8,389,612 8,179,680 7,725,343 7,580,000 6,882,316 7,421,280 5,965,012 8,271,912 9,736,264 5,392,500 2,550,000 1,950,000 2,920, ,000 1,700,000 1,091, , , ,500 4,085,000 4,045,000 4,085,000 4,045,000 4,085,000 4,045,000 4,085,000 4,045,000 4,085,000 6,365, , , , , , , , , , ,000 17,338,506 16,409,612 15,964,680 16,440,343 14,150,000 14,377,316 14,347,592 12,319,512 15,130,412 18,223,764 1,250,000 55,125 57,881 60,775 63,814 67,005 70,355 73,873 77,566 81,444 18,588,506 16,464,737 16,022,561 16,501,118 14,213,814 14,444,321 14,417,947 12,393,385 15,207,978 18,305,208 Table 67(a) Capital Expenditure Category Annual Budget Spend 2012 to

165 NETWORK DEVELOPMENT PLANNING YEAR 1 YEAR 2 YEAR 3 YEAR 4 YEAR 5 YEAR 6 YEAR 7 YEAR 8 YEAR 9 YEAR 10 FOR YEAR ENDED Major Projects - Distribution Overhead Line ,000,000 1,000,000 1,000, ,500, ,000 1,680,000 Major Projects - Sub-transmission Cable 3,100, ,500, ,500,000 2,000, Major Projects - Sub-transmission 1,650, ,000 2,650,000 1,000,000 1,700, ,000 3,000,000 2,600,000 4,500,000 6,500,000 Overhead Line Major Projects - Transmission Overhead 2,266,667 2,266,667 2,266, Line Major Projects - Zone Substation 800,000 2,550, ,124,000 1,676,000 2,140,000 4,000, ,000 2,500, ,000 Major Projects - Subtotal 7,816,667 5,316,667 6,416,667 8,124,000 6,876,000 5,790,000 7,000,000 4,600,000 7,750,000 8,680,000 Non System Fixed / Customer Connection 2,250,000 1,255,125 1,557,881 1,560,775 1,563,814 1,567,005 1,570,355 1,573,873 1,577,566 1,581,444 Other Projects Sub-transmission & Distribution Sub-transmission & Distribution General R&R Total direct expenditure on distribution network 4,261,839 5,622,945 3,713,013 2,521,343 1,439,000 2,792,316 1,512,592 1,924,512 1,425,412 1,428,764 4,260,000 4,270,000 4,335,000 4,295,000 4,335,000 4,295,000 4,335,000 4,295,000 4,455,000 6,615,000 18,588,506 16,464,737 16,022,561 16,501,118 14,213,814 14,444,321 14,417,947 12,393,385 15,207,978 18,305,208 Table 67(b) Capital Expenditure Breakdown for Major Projects and Asset Class 2012 to

166 LIFE CYCLE ASSET MANAGEMENT Section 6 Life Cycle Asset Management 6.1 Maintenance and Renewal Planning Criteria and Assumptions Maintenance and Renewal Criteria Maintenance/ Renewal Planning Strategies Maintenance and Renewal Planning Assumptions Overhead Conductors Failure Modes and Risks Associated with Overhead Conductors Planned Inspection & Maintenance Practices for Overhead Conductors Vegetation Strategy Regulatory Compliance Reliability Far North District Council Relationship Targeted Cutting Strategy Cutting and Cost Projections Life Cycle Expenditure Forecast Overhead Conductors Poles and Structures Failure modes and risks associated with poles and structures Error! Bookmark not defined Failure Modes and Risks Associated with poles and structures Planned Inspection & Maintenance Practices for Poles and Structures Asset Renewal Programme Life Cycle Expenditure Forecast Poles & Structures Underground & Submarine Cables Failure Modes and Risks Associated with Underground & Submarine Cables Planned Inspection & Maintenance Practices for Underground & Submarine Cables Asset Renewal Program Life Cycle Expenditure Forecast Underground & Submarine Cables Distribution & SWER Transformers Failure Modes and Risks Associated with Distribution & SWER Transformers Planned Inspection & Maintenance Practices for Distribution & SWER Transformers Asset Renewal Program Life Cycle Expenditure Forecast Distribution & SWER Transformers Auto-Reclosers Failure Modes and Risks Associated with Auto-Reclosers Planned Inspection & Maintenance Practices for Auto-Reclosers Asset Renewal Program Life Cycle Expenditure Forecast Auto-Reclosers Regulators

167 LIFE CYCLE ASSET MANAGEMENT Failure Modes and Risks Associated with Regulators Planned Inspection & Maintenance Practices for Regulators Asset Renewal Program Life Cycle Expenditure Forecast Regulators Ring Main Units (RMU) Failure Modes and Risks Associated with Ring Main Units Planned Inspection & Maintenance Practices for Ring Main Units Asset Renewal Program Life Cycle Expenditure Forecast Ring Main Units Sectionalisers Failure Modes and Risks Associated with Sectionalisers Planned Inspection & Maintenance Practices for Sectionalisers Asset Renewal Program Life Cycle Expenditure Forecast Sectionalisers Capacitors Failure Modes and Risks Associated with Capacitors Planned Inspection & Maintenance Practices for Capacitors Asset Renewal Program Life Cycle Expenditure Forecast Capacitors Zone Substation Transformers Failure Modes and Risks Associated with Zone Substation Transformers Planned Inspection & Maintenance Practices for Zone Substation Transformers Asset Renewal Program Life Cycle Expenditure Forecast Zone Substation Transformers Circuit Breakers Failure Modes and Risks Associated with Circuit Breakers Planned Inspection & Maintenance Practices for Circuit Breakers Asset Renewal Program Life Cycle Expenditure Forecast Circuit Breakers Zone Substation Structures Failure Modes and Risks Associated with Zone Substation Structures Planned Inspection & Maintenance Practices for Zone Substation Structures Asset Renewal Program Life Cycle Expenditure Forecast Zone Substation Structures 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

168 LIFE CYCLE ASSET MANAGEMENT Life Cycle Expenditure Forecast Zone Substation DC Systems Zone Substation Protection Failure Modes and Risks Associated with Zone Substation Protection Planned Inspection & Maintenance Practices for Zone Substation Protection Asset Renewal Program Life Cycle Expenditure Forecast Zone Substation Protection Zone Substation Grounds and Buildings Failure Modes and Risks Associated with Zone Substation Grounds & Buildings Planned Inspection & Maintenance Practices for Zone Substation Grounds & Buildings Asset Renewal Program Life Cycle Expenditure Forecast Zone Substation Grounds & Buildings Customer Service Pillars Failure Modes and Risks Associated with Customer Service Pillars Planned Inspection & Maintenance Practices for Customer Service Pillars Asset Renewal Program Life Cycle Expenditure Forecast Customer Service Pillars Earth installations Failure Modes and Risks Associated with Earth Installations Planned Inspection & Maintenance Practices for Earth Installations Asset Renewal Program Life Cycle Expenditure Forecast Earth Installations Life Cycle Expenditure Forecast SCADA and Communications Load Control Plant Failure Modes and Risks Associated with Load Control Plant Planned Inspection & Maintenance Practices for Load Control Plant Asset Renewal Program Life Cycle Expenditure Forecast Load Control Plant Total Maintenance and Renewal Expenditure Forecast Maintenance Spend by Commerce Commission Category Renewal Maintenance Spend by Asset Class (2016 to 2020).. Error! Bookmark not defined Asset Replacement Spend by Asset Class (2011 to 2015) Asset Replacement Spend by Asset Class (2016 to 2020)

169 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. The economic lives of assets used in this section are based on the Commerce Commission s ODV Handbook. 6.1 Maintenance and Renewal Planning Criteria and Assumptions Maintenance and Renewal Criteria The overall objective of Top Energy s 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. 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. Undertaking performance and condition monitoring of critical assets. Economic analysis is undertaken for significant decisions related to lifecycle optimisation (operations, planned/reactive maintenance, renewals, etc.) 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 Top Energy s planned maintenance programmes fall into two distinct categories: 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 programme includes other activities, such as vegetation management and non-invasive condition assessment that are implemented on a regular time based cycle and are considered necessary to maintain the reliability of the network and ensure that assets continue to function as designed. Renewal Maintenance - Condition based maintenance is based on an assessment of an asset s physical condition. This philosophy entails performing maintenance only when safety, reliability and performance are compromised beyond acceptable limits. The objectives of condition based maintenance are prevention of unplanned faults, making optimal use of maintenance resources and maximising the operational and economic life of network assets. Defects to be addressed under the condition based maintenance programme are generally identified through asset inspection and non-invasive condition assessment activities. While age generally 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 assess and budget for forward renewal maintenance and asset replacement requirements. Risk Reactive Maintenance This covers fault, near fault and high risk situations where an asset requires immediate or urgent attention. These are unplanned activities on Top Energy s network and are driven by asset failure due to third party interference, foreign interference, storm events or sudden component failure. 167

170 LIFE CYCLE ASSET MANAGEMENT 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 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. Figure 72 below shows the forecast expenditure on preventative maintenance (MP), renewal maintenance (MR), faults and vegetation management for the planning period. It excludes expenditure for asset replacement and network growth. Figure 70 Maintenance Expenditure Forecast Maintenance/ Renewal Planning Strategies Up until recently Top Energy had a very rudimentary maintenance planning process and very limited access to asset information and thus the maintenance strategy was very much reactive. Until 2003, geographic asset information was CAD based. In 2003 the process for gathering GPS data for assets began. In 2004 migration of the CAD system to an electronic GIS was undertaken. In the meantime GPS data continued to be captured and loaded into GIS. This process peaked in and was completed in 2008, except for the low voltage system where data collection is ongoing. Now with a strong foundation of accurate network information a robust maintenance program can be introduced. This was implemented in It quickly became apparent that an asset maintenance management system was needed as spreadsheets became too cumbersome to manage. An asset management database was assembled in 2009 to record, organise and process the asset condition data that was being generated from routine inspections. The next step in this development is to investigate the implementation of a proprietary asset maintenance management system in followed by full implementation in Top Energy has adopted the following broad operational and maintenance strategies. The detailed programmes are discussed in the asset specific sections which follow. 168

171 a) Preventative maintenance Programme LIFE CYCLE ASSET MANAGEMENT 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 table 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 & Communications Radio Repeater Communications Annual Substation Equipment Communications 2 Year Field Equipment Communications 3 Year Vegetation Management Pole Mounted Assets 33kV Annual 22kV 3 Year Ground Mounted Assets 33kV Annual b) Table 67 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 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. Having completed the first year of the new routine maintenance program 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 169

172 Work Planning As Builds Fault Remediation Remediation Complete LIFE CYCLE ASSET MANAGEMENT continuous improvement to methodology. Asset condition is rated and remediation planned as summarised in Figure 73. a) 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 interrogated and maintenance is scheduled based on the priority assigned during the assets inspection. The asset management database is checked periodically to ensure that action can be 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 73 below shows the Information Flow Chart for condition based maintenance planning. 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 71 b) Remedial Maintenance Information flow chart condition based assessment 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. Thus 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 170

173 LIFE CYCLE ASSET MANAGEMENT outside of preventative maintenance are rated as summarised in Table 68 and the appropriate action is taken. c) 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 table below is summarised from TE-NW-AM-02 Condition Reporting & Remediation of Network Assets. PRIORITY ISSUE RESPONSE TIME X Very High Critical Fault or near fault. Remediate within 48 hours. A High Urgent Unplanned, end of life. Remediate within 3 months. B Medium Routine Planned, end of life. Remediate within 12 months. C Low Monitor Approaching end of life. No remediation timeframe. Monitor condition. D Very Low Passive No operational impact. No remediation timeframe. May be left indefinitely. Table 68 The assumptions are: Response priority definitions 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 (vegetation clearances, voltage compliance etc) 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 ongoing 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. 171

174 LIFE CYCLE ASSET MANAGEMENT 6.2 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; 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. Though 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 following: Condition Assessment Structures Condition Assessment Conductors Vegetation Assessment Sub-transmission, distribution and low voltage support structures are visually inspected on a three year cycle. Ground based visual inspection of sub-transmission, distribution and low voltage conductors are done on a three year cycle. Thermal imaging of subtransmission lines is conducted annually and six yearly for distribution conductors. Helicopter based inspection of sub-transmission lines is conducted six yearly supplemented by the occasional inspections initiated for fault or operational reasons. 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 section and at the end of Section Vegetation Strategy 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 will be born by Top Energy but as the tree owners are identified and the compulsory first cut and trim on the tree is complete the ongoing maintenance will be passed to 172

175 LIFE CYCLE ASSET MANAGEMENT the tree owner. It is Top Energy s preference to remove trees where practical and economic to do so to minimise ongoing 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 74 below demonstrates a steadily increasing trend in overall network vegetation related faults. This has been recognised and a significant investment in resource was made at the beginning of the financial year ending The worst affected feeders were targeted and the effect of this can be clearly seen by a significant drop in the number of outages in the first two years of the program. Figure 72 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 Reliability Figure 75 below demonstrates that 40 of Top Energy s distribution feeders and 33kV lines have suffered Vegetation related events over the past five years, whilst the top ten worst performing feeders contribute 58%, the top fifteen contribute 73% and the top 20 contribute 83% of the total vegetation faults. 173

176 Totara North Russell South Road Whangaroa Rawene Rangiahua Te Kao Taheke Horeke Opononi Oruru Towai Ohaeawai Awarua Puketona Opua Purerua Riverview China Clay Aerodrome Road Awanui Onewhero Tokerau Tau Block Moerewa Oxford Street Kawakawa Pokapu Herekino Joyces Road Pukenui South Tii Bay AFFCO Kawakawa#1 Mangonui Pukenui Waipapa#1 Kaikohe NRCF Redan Road LIFE CYCLE ASSET MANAGEMENT Tree Contacts Tree Contacts Figure 73 Vegetation interruption count per feeder/33kv line Far North District Council 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 NZ tree legislation 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 Targeted Cutting Strategy The 2012 year will be the final year of an intensive three-year vegetation management strategy that commenced in April The purpose of the programme is to regain control of tree related outages. This will then evolve into a structured maintenance program of monitoring, trimming and removal of new trees and requiring tree owners to take responsibility for keeping existing trees clear of lines. The programme incorporates a three stage strategy. Stage one is an intensive vegetation removal program to clear all trees from power lines and the transfer of responsibility from TEN to the tree owner. Stage two will be regular patrol and maintenance program where new trees will be identified, trimmed/removed and the responsibility transferred to the tree owner as well as notifying tree owners that previously trimmed trees now require their attention. In parallel to stage one and two will be stage three which will effectively be a reactive component in response to customer enquiries to minimise disruption to the planned cutting programme. The vegetation management programme for 2012 is shown below. 2011/ kV Circuits: Patrol and maintain. Kaikohe Substation: Intensive vegetation removal. Kawakawa Substation: Patrol and maintain. Moerewa Substation: Intensive vegetation removal. 174

177 LIFE CYCLE ASSET MANAGEMENT Waipapa Substation: Patrol and maintain. Omania Substation: Patrol and maintain. Haruru Substation: Intensive vegetation removal. Okahu Substation: Patrol and maintain. Taipa Substation: Patrol and maintain. Pukenui Substation: Intensive vegetation removal. NPL Substation: Intensive vegetation removal. The figure below shows the information flows used to manage the vegetation control programme. Top Energy Customer Investigation Enqueries 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 74 Information Flow Vegetation Control Cutting and Cost Projections It is proposed to spend approximately $3M each year of the programme. It is estimated that this would remove most of the high priority tree problems, transfer responsibility for future vegetation management over to the tree owners and discharge our statutory obligations Life Cycle Expenditure Forecast Overhead Conductors The table below shows the projected operations, maintenance and renewal expenditure for the next 2 years. The 10-year financial forecast for operations and maintenance activities to asset level is detailed at the end of this section. FINANCIAL YEAR ENDING $000 $000 Operational Expenditure 3, ,000.0 [MP] Vegetation Line Inspection & Tree Owner Liaison [MP] Vegetation Cutting Top Energy Network 2, [MP] Preventative Maintenance & Inspection [MR] Renewal Maintenance Capital Expenditure [RR] Renewal Replacement Table 69 Life Cycle Expenditure Forecast OH conductors 175

178 LIFE CYCLE ASSET MANAGEMENT 6.3 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 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 thus 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 and are designated as L-Shape poles due to their cross sectional profile. 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 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 yearly 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 may be used if the existing tests prove to be inadequate for planning purposes. 176

179 LIFE CYCLE ASSET MANAGEMENT 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 beyond economic repair. 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 are 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 Life Cycle Expenditure Forecast Poles & Structures The table below shows the projected operations, maintenance and renewal expenditure for the next 2 years. The 10-year financial forecast for operations and maintenance activities to asset level is detailed at the end of this section. FINANCIAL YEAR ENDING $000 $000 Operational Expenditure [MP] Preventative Maintenance & Inspection [MR] Renewal Maintenance Capital Expenditure [RR] Renewal Replacement Table 70 Life Cycle Expenditure Forecast poles and structures 6.4 Underground & Submarine Cables Failure Modes and Risks Associated with Underground & Submarine Cables The main cause of failure in cables is third party damage usually 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 larger township loads, this can be mitigated by installing alternative circuits. For HV cables failure of a cable termination is much more likely than electrical failure of the cable itself. Ongoing 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. 177

180 LIFE CYCLE ASSET MANAGEMENT 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 5 yearly on-line PD mapping of all 11kV and 33kV cables entering zone substations. Submarine cables are tested 5 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. 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 replacement as 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 Life Cycle Expenditure Forecast Underground & Submarine Cables The table below show expenditure for the next 3 years. The 10 year financial forecast for operations and maintenance activities to asset level is detailed at the end of this section. FINANCIAL YEAR ENDING $000 $000 Operational Expenditure [MP] Preventative Maintenance & Inspection [MR] Renewal Maintenance Capital Expenditure [RR] Renewal Replacement Table 71 Life Cycle Expenditure Forecast Underground & Submarine Cables 178

181 LIFE CYCLE ASSET MANAGEMENT 6.5 Distribution & SWER Transformers Failure Modes and Risks Associated with Distribution & SWER Transformers The main causes of failure of distribution & SWER transformers are lightning, corrosion, over-loading and oil leaks. Top Energy is in the process of minimising 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 resulting 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 & Maintenance Practices for Distribution & SWER Transformers Distribution transformers are inspected 3 yearly. In addition to the normal condition monitoring inspections, all ground mounted transformers are inspected yearly 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 and 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 degradation or damage are replaced and the old unit is refurbished if viable or scrapped. The assessment process considers several factors; often more than one factor is applicable. In summary the process is: All pole mount units less than 50kVA subjected to an electrical fault or failure condition assessment are assessed for repairs. These units are written off if the repair/refurbishment cost of the unit is higher than the cost of a new unit; All pole mount transformers 50kVA and above are assessed. If repair costs (including transport), is >75% of replacement cost, then these are written off. All pad mount units are assessed; these are typically larger units. If repair cost (including transport) is >75% of replacement cost, then these are written off. As a general principle, distribution transformer replacement is based on condition or is driven by load growth Asset Renewal Program 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. 179

182 LIFE CYCLE ASSET MANAGEMENT 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 Life Cycle Expenditure Forecast Distribution & SWER Transformers The table below shows the projected operations, maintenance and renewal expenditure for the next 2 years. The 10-year financial forecast for operations and maintenance activities to asset level is detailed at the end of this section. FINANCIAL YEAR ENDING $000 $000 Operational Expenditure [MP] Preventative Maintenance & Inspection [MR] Renewal Maintenance Capital Expenditure [RR] Renewal Replacement Table 72 Life Cycle Expenditure Forecast Distribution & SWER Transformers 6.6 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 lead 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 & 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 Life Cycle Expenditure Forecast Auto-Reclosers The table below shows the projected operations, maintenance and renewal expenditure for the next 2 years. The 10-year financial forecast for operations and maintenance activities to asset level is detailed at the end of this section. 180

183 LIFE CYCLE ASSET MANAGEMENT FINANCIAL YEAR ENDING $000 $000 Operational Expenditure [MP] Preventative Maintenance & Inspection [MR] Renewal Maintenance Capital Expenditure [RR] Renewal Replacement Table 73 Life Cycle Expenditure Forecast Auto-Reclosers 6.7 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 & 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 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 for this asset class Life Cycle Expenditure Forecast Regulators The table below shows the projected operations, maintenance and renewal expenditure for the next 2 years. The 10-year financial forecast for operations and maintenance activities to asset level is detailed at the end of this section. FINANCIAL YEAR ENDING $000 $000 Operational Expenditure [MP] Preventative Maintenance & Inspection [MR] Renewal Maintenance Capital Expenditure [RR] Renewal Replacement Table 74 Life Cycle Expenditure Forecast Regulators 6.8 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. 181

184 LIFE CYCLE ASSET MANAGEMENT Planned Inspection & Maintenance Practices for Ring Main Units Ring Main Units 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/ Life Cycle Expenditure Forecast Ring Main Units The table below shows the projected operations, maintenance and renewal expenditure for the next 2 years. The 10-year financial forecast for operations and maintenance activities to asset level is detailed at the end of this section. FINANCIAL YEAR ENDING $000 $000 Operational Expenditure [MP] Preventative Maintenance & Inspection [MR] Renewal Maintenance Capital Expenditure [RR] Renewal Replacement Table 75 Life Cycle Expenditure Forecast Ring Main Units 6.9 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 Life Cycle Expenditure Forecast Sectionalisers The table below shows the projected operations, maintenance and renewal expenditure for the next 2 years. The 10-year financial forecast for operations and maintenance activities to asset level is detailed at the end of this section. 182

185 LIFE CYCLE ASSET MANAGEMENT FINANCIAL YEAR ENDING $000 $000 Operational Expenditure [MP] Preventative Maintenance & Inspection [MR] Renewal Maintenance Capital Expenditure [RR] Renewal Replacement Table 76 Life Cycle Expenditure Forecast Sectionalisers 6.10 Capacitors Failure Modes and Risks Associated with Capacitors The main causes of failure of capacitors are lightning and sudden mechanical failure Planned Inspection & Maintenance Practices for Capacitors 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; 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 Life Cycle Expenditure Forecast Capacitors The table below shows the projected operations, maintenance and renewal expenditure for the next 2 years. The 10-year financial forecast for operations and maintenance activities to asset level is detailed at the end of this section. FINANCIAL YEAR ENDING $000 $000 Operational Expenditure [MP] Preventative Maintenance & Inspection [MR] Renewal Maintenance Capital Expenditure [RR] Renewal Replacement Table 77 Life Cycle Expenditure Forecast Capacitors 6.11 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. 183

186 LIFE CYCLE ASSET MANAGEMENT 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 & Maintenance Practices for Zone Substation Transformers An annual programme of dissolved gas analysis (DGA), 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 spreadsheet 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); Rogers Ratios (invoked only when gas levels reach a certain level); and Other tests, condition assessment, history, circumstances, age, and design. 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 etc.), 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. 184

187 LIFE CYCLE ASSET MANAGEMENT The overall condition of TEN s zone substation transformers is above average according to existing oil tests. Primary condition concerns are leaks and investigations are scheduled for 2010/11 to determine the source and cause of these to aid in maintenance planning. 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 Omania Substation to replace the three single phase transformers that are approaching end of life and are reaching capacity Life Cycle Expenditure Forecast Zone Substation Transformers The table below shows the projected operations, maintenance and renewal expenditure for the next 2 years. The 10-year financial forecast for operations and maintenance activities to asset level is detailed at the end of this section. FINANCIAL YEAR ENDING $000 $000 Operational Expenditure [MP] Preventative Maintenance & Inspection [MR] Renewal Maintenance Capital Expenditure [RR] Renewal Replacement Table 78 Life Cycle Expenditure Forecast Zone Substation Transformers 6.12 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 Planned Inspection & Maintenance Practices for Circuit Breakers 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; 185

188 LIFE CYCLE ASSET MANAGEMENT 33 kv vacuum interrupter / oil insulated are service four yearly. 33 kv vacuum interrupter / air insulated are service four yearly. 33 kv minimum oil circuit breakers are serviced yearly. 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. Two yearly 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 Life Cycle Expenditure Forecast Circuit Breakers The table below shows the projected operations, maintenance and renewal expenditure for the next 2 years. The 10-year financial forecast for operations and maintenance activities to asset level is detailed at the end of this section. FINANCIAL YEAR ENDING $000 $000 Operational Expenditure [MP] Preventative Maintenance & Inspection [MR] Renewal Maintenance Capital Expenditure [RR] Renewal Replacement Table 79 Life Cycle Expenditure Forecast Circuit Breakers 6.13 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 & 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 having the bus reconfigured to allow the mobile substation to be connected and obsolete switchgear replaced. Modern protection systems have been installed. 186

189 LIFE CYCLE ASSET MANAGEMENT Moerewa Substation has been identified as needing attention. Investigations will be carried out with respect to design and operation. Completion for this work has yet to be defined Life Cycle Expenditure Forecast Zone Substation Structures The table below shows the projected operations, maintenance and renewal expenditure for the next 2 years. The 10-year financial forecast for operations and maintenance activities to asset level is detailed at the end of this section. FINANCIAL YEAR ENDING $000 $000 Operational Expenditure [MP] Preventative Maintenance & Inspection [MR] Renewal Maintenance Capital Expenditure [RR] Renewal Replacement Table 80 Life Cycle Expenditure Forecast Zone Substation Structures 6.14 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 for this asset class Life Cycle Expenditure Forecast Zone Substation DC Systems The table below shows the projected operations, maintenance and renewal expenditure for the next 2 years. The 10-year financial forecast for operations and maintenance activities to asset level is detailed at the end of this section. FINANCIAL YEAR ENDING $000 $000 Operational Expenditure [MP] Preventative Maintenance & Inspection [MR] Renewal Maintenance Capital Expenditure [RR] Renewal Replacement Table 81 Life Cycle Expenditure Forecast Zone Substation DC Systems 187

190 LIFE CYCLE ASSET MANAGEMENT 6.15 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 & Maintenance Practices for Zone Substation Protection Until the upgrade 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; 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 relays will provide the opportunity to increase the interval of calibration testing beyond four years. Top Energy will maintain four yearly calibration testing even with the new protection regime and then consider extending this, ultimately to 8-10 yearly. This would be done once TEN is satisfied that on-board continuous monitoring is fully in place and functioning. 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 Life Cycle Expenditure Forecast Zone Substation Protection The table below shows the projected operations, maintenance and renewal expenditure for the next 2 years. The 10-year financial forecast for operations and maintenance activities to asset level is detailed at the end of this section. FINANCIAL YEAR ENDING $000 $000 Operational Expenditure [MP] Preventative Maintenance & Inspection [MR] Renewal Maintenance Capital Expenditure [RR] Renewal Replacement Table 82 Life Cycle Expenditure Forecast Zone Substation Protection 188

191 LIFE CYCLE ASSET MANAGEMENT 6.16 Zone Substation Grounds and Buildings Failure Modes and Risks Associated with Zone Substation Grounds & 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 & Maintenance Practices for Zone Substation Grounds & 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 Life Cycle Expenditure Forecast Zone Substation Grounds & Buildings The table below shows the projected operations, maintenance and renewal expenditure for the next 2 years. The 10-year financial forecast for operations and maintenance activities to asset level is detailed at the end of this section. FINANCIAL YEAR ENDING $000 $000 Operational Expenditure [MP] Preventative Maintenance & Inspection [MR] Renewal Maintenance Capital Expenditure [RR] Renewal Replacement Table 83 Life Cycle Expenditure Forecast Zone Substation Grounds & Buildings 6.17 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 exception being 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 & 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. 189

192 LIFE CYCLE ASSET MANAGEMENT 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 the 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 ongoing issue of failure from poor connections. Being a sealed unit these units also provide waterproofing and protection against incidental contact Asset Renewal Program Pillars are far from 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 Life Cycle Expenditure Forecast Customer Service Pillars The table below shows the projected operations, maintenance and renewal expenditure for the next 2 years. The 10-year financial forecast for operations and maintenance activities to asset level is detailed at the end of this section. FINANCIAL YEAR ENDING $000 $000 Operational Expenditure [MP] Preventative Maintenance & Inspection [MR] Renewal Maintenance Capital Expenditure [RR] Renewal Replacement Table 84 Life Cycle Expenditure Forecast Customer Service Pillars 6.18 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 & Maintenance Practices for Earth Installations Distribution equipment earths are tested three yearly whereas zone substation earth mats are tested annually. The budget for earth testing is associated with the respective asset that the earth system is attached to and therefore does not appear in this section. 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, 190

193 Forecasted Earth Remediation Budget Update Earth Remediation Budget LIFE CYCLE ASSET MANAGEMENT i.e. shopping areas, schools etc. 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 75 Information flow chart earth testing and remediation Asset Renewal Program Earth systems for distribution equipment have been very simplistic. Recent reviews of earthing practices have shown that standards are lacking somewhat. TEN s earthing standards have been 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 over the following two years Life Cycle Expenditure Forecast Earth Installations The table below shows the projected operations, maintenance and renewal expenditure for the next 2 years. The 10-year financial forecast for operations and maintenance activities to asset level is detailed at the end of this section. FINANCIAL YEAR ENDING $000 $000 Operational Expenditure [MP] Preventative Maintenance & Inspection* [MR] Renewal Maintenance Capital Expenditure [RR] Renewal Replacement *NOTE: Preventative Maintenance & Inspections budget for earth testing is included with their respective assets. Table 85 Life Cycle Expenditure Forecast Earth Installations 191

194 LIFE CYCLE ASSET MANAGEMENT 6.19 SCADA & Communications Failure Modes and Risks Associated with SCADA and Communications SCADA systems can fail for a number of reasons; 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 without event Planned Inspection & 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 necessary review of the maintenance strategy. The installation of this new equipment with its onboard diagnostics information has made it easier to monitor the systems and alarm the network assets for operation outside of normal parameters. At 2 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 & 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 Life Cycle Expenditure Forecast SCADA and Communications The table below shows the projected operations, maintenance and renewal expenditure for the next 2 years. The 10-year financial forecast for operations and maintenance activities to asset level is detailed at the end of this section. FINANCIAL YEAR ENDING $000 $000 Operational Expenditure [MP] Preventative Maintenance & Inspection [MR] Renewal Maintenance Capital Expenditure [RR] Renewal Replacement Table 86 Life Cycle Expenditure Forecast SCADA and Communications 192

195 LIFE CYCLE ASSET MANAGEMENT 6.20 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; Holding a support contract with the system vendor including access to specialist parts if required Planned Inspection & 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 Life Cycle Expenditure Forecast Load Control Plant The table below shows the projected operations, maintenance and renewal expenditure for the next 2 years. The 10-year financial forecast for operations and maintenance activities to asset level is detailed at the end of this section. FINANCIAL YEAR ENDING $000 $000 Operational Expenditure [MP] Preventative Maintenance & Inspection [MR] Renewal Maintenance Capital Expenditure [RR] Renewal Replacement Table 87 Life Cycle Expenditure Forecast Load Control Plant 193

196 LIFE CYCLE ASSET MANAGEMENT 6.21 Total Maintenance and Renewal Expenditure Forecast Tables 88 through 90, shows the split of expenditure by category for maintenance driven tasks for the ten year planning period Maintenance Driven Expenditure by Commerce Commission Category FINANCIAL YEAR ENDING EXPENDITURE TYPE Preventative Maintenance 4,100,000 2,100,000 2,100,000 2,100,000 2,100,000 2,100,000 2,100,000 2,100,000 2,100,000 2,100,000 Renewal Maintenance 1,077, , ,000 1,020,000 1,183,500 1,102,500 1,282,500 1,410,000 1,520,000 1,745,000 Fault and Emergency Maintenance 900, , , , , , , , , ,000 Subtotal - Operational Expenditure 6,077,500 3,720,000 3,820,000 4,020,000 4,183,500 4,102,500 4,282,500 4,410,000 4,520,000 4,745,000 Renewal Replacement 2,010,000 1,620,000 2,100,000 2,072,000 4,045,000 4,008,500 2,664,000 2,699,500 3,209,000 4,298,000 Reliability, Safety & Environment Replacement 500, , , , , , , , ,000 Subtotal - Capital Expenditure 2,510,000 2,600,000 2,600,000 2,572,000 4,545,000 4,508,500 3,144,000 3,179,500 3,209,000 4,778,000 TOTAL - COMBINED EXPENDITURE 8,587,500 6,320,000 6,420,000 6,592,000 8,728,500 8,611,000 7,426,500 7,589,500 7,729,000 9,523,000 Table 88 Maintenance Driven Expenditure by Commerce Commission Category 194

197 LIFE CYCLE ASSET MANAGEMENT Maintenance Driven Operational Expenditure The table below illustrates key spend areas in operational maintenance expenditure over the ten year planning period. Asset Type Fault Contingency 900, , , , , , , , , ,000 High Voltage Cross Arms , ,000 1,000,000 Safety & Compliance 100, , , , , , , , , ,000 Asset Inspection 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 Vegetation Management 3,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 Maintenance Contingency 720, , , , , , , , , ,000 Mobile Substation , Sub Transmission Cross Arms 307, , , , , , Substation Building & Grounds 50, , , ,000 Grand Total 6,077,500 3,720,000 3,820,000 4,020,000 4,183,500 4,102,500 4,282,500 4,410,000 4,520,000 4,745,000 Table 89 Breakdown of Maintenance Driven Operational Expenditure 195

198 LIFE CYCLE ASSET MANAGEMENT Maintenance Driven Capital Expenditure The table below illustrates key spend areas in capital maintenance expenditure over the ten year planning period. Asset Type Fault Contingency 360, , , , , , , , , ,000 High Voltage Pole 250, ,197,500 1,125, ,500 1,125,000 2,250,000 High Voltage Switch 180, ,000 1,926, , , , ,000 0 High Voltage Transformer , Maintenance Contingency 900, , , , , , , , , ,000 No Break Power System 40, Service Pillar ,326, , ,000 Sub Transmission Pole 160, , , , , , ,000 Substation 120, Grand Total 2,010,000 1,620,000 2,100,000 2,072,000 4,045,000 4,008,500 2,664,000 2,699,500 3,209,000 4,298,000 Table 90 Breakdown of Maintenance Driven Capital Expenditure 196

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

200 RISK MANAGEMENT 7 Risk Management 7.1 Risk Management Policy The governance of Top Energy lies with the Board of Directors. The Executive Management Team has the responsibility and accountability for the representation, direction and business success of Top Energy. This requires a 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 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 via 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) & 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 but 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 risks 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; 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, flood etc, all within the past experience of Top Energy and other similar electricity companies. Risk events which could be deemed fanciful are not included in contingency plans. For example, aircraft crashing into substations where these substations are not near airfields or on recognised approach paths to airports 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 s form this Risk Committee: Chief Executive Officer 198

201 RISK MANAGEMENT General Manager Network Asset Top Energy 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, organize two monthly meetings and is 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 controls are actioned; 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 Top Energy Board of Directorsfor approval at the same time. The table below outlines the cyclical review and reporting activities associated with Top Energy s risk management process. ACTIVITY RESPONSIBILITY FREQUENCY Update Risk Register All Staff As required Review Risks Contained Within Risk Register Risk Committee Two Monthly Risk Register / Plan to the Board Executive Management Annually Approve Risk Register Board Annually Table 90 Risk management review and reporting cycle 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 then this is used in the risk analysis. 199

202 RISK MANAGEMENT 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 76 Top Energy risk management process The risk process adopted, which is consistent with AS/ NZS 4360:2004, incorporates the steps shown in Figure 78. 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 Financial Products /Services 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 Changed Stakeholder Expectations Poorly managed change processes Revenue loss or constraints Increased Expense flows liability arising from Product or service delivery 200

203 RISK MANAGEMENT GENERAL MANAGEMENT Technology CONSEQUENCE ARISING FROM POOR MANAGEMENT PRACTICES High reliance on specific technologies Impact relating to the failure of technology Impact of significant technological changes Table 91 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 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 D. Risk treatment: Defining the actions to remove, mitigate or prepare for the risk. This involves contingency plans where appropriate Risk analysis outcome The next table 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. 201

204 RISK MANAGEMENT Table 92 Top ten risks identified 202

205 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 more concerned by the fact that the Company has breached its reliability thresholds in recent years and are concerned that despite the extenuating circumstances there is a growing risk that the regulator could interfere directly with the operation of the Company. Also of seriously 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. There is reduced external development work available as a result of the economic situation causing pressure to reduce staff accordingly. The reviews identified the Company s ability to retain an adequate pool of skilled labour to meet the medium term construction needs of the network if it allows staff numbers to drop as risk. The common timing of these risks, together with their significance has resulted in a strategic decision being made to targeting reliability and capacity improvement 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 seeing a reduction in both the frequency and severity of injuries to staff, contractors and the general public. The results in both of these areas demonstrate the commitment by staff to effectively manage Health and Safety. Refer to the figure below for Top Energy s Lost Time Injury Frequency Rate (LTIFR) for the year 2008/09 along with the historical results since 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; Management of contractors and sub-contractors. Of these recent efforts have seen a major improvement being made in the time frames and process for the reporting and investigation of incidents 203

206 RISK MANAGEMENT Figure 77 Top Energy s Lost Time Injury Frequency Rate (LTIFR) Employee commitment continues to grow alongside the continued development of SafeTeams which involve all employees at all levels, in the management of Health and Safety by having them take part 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 Unit Standard based training towards appropriate National Certificates for their various roles. Top Energy offers training to up skill existing employees in the area of Hotstick, Glove and Barrier, Close Proximity Vegetation, Utility Arborist techniques and Control Room Operator roles. This demonstrates commitment to our 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 CEO. This is expected to further enhance Top Energy's overall performance 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 load to the grid exit points and secondly, by way of lost consumer confidence in electricity as a reliable energy source. Top Energy understands that Transpower has undertaken its own assessment of risk and supports efforts and projects that reduce or mitigate these transmission risks. There is ongoing consultation with Transpower on these matters 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 furthermore has joined a cooperative group of other infrastructural organisations to provide mutual risk mitigation in this area. 204

207 RISK MANAGEMENT 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 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 & 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 which 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. 205

208 RISK MANAGEMENT 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 J 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 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. promote ongoing research and technology transfer aimed at protecting and preserving the lifelines of the region. 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. 206

209 RISK MANAGEMENT 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 it s 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 shed priority (manual and automatic) by under frequency zone and sub-station 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 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 thus reduce planned consumer outages Risk Register Top Energy s Risk Register, as developed by the Risk Committee, is held in a Spreadsheet. 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 ongoing basis. 207

210 EVALUATION OF PERFORMANCE 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

211 EVALUATION OF PERFORMANCE 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 year end 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 dramatically improved from YE 2009 and the Company s target. There were a total of: kV and 33kV Top Energy faults, and 159 Top Energy planned outages. RELIABILITY MEASURE YE 2009 TARGET YE 2009 ACTUAL YE 2010 TARGET YE 2010 ACTUAL SAIDI (Excludes Transpower) SAIFI (Excludes Transpower) Number of customers Without Power for 24 hours ALL Causes Number of Customers Without Power for more then 3hrs ALL Causes <25 1,491 < ,000 29,400 7,000 19,976 Table 93 Network reliability performance The most significant causes of Top Energy unplanned interruptions in YE 2010 were adverse weather, tree contacts, lightning and defective equipment, as indicated in the table below. A detailed breakdown of outage statistics is shown in Table 95 overleaf. TOP ENERGY CAUSE OF UNPLANNED INTERRUPTION SAIDI % OF TOTAL Adverse Environment Adverse Weather Defective Equip Foreign Interference Human Element Lightning Tree Contacts Unknown Total Table 94 Network reliability performance 209

212 EVALUATION OF PERFORMANCE 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 Subtotal: Top Energy Planned Outages Planned Capital Extension Planned - Planned External Work Planned - Planned Fault Prevention Planned General Planned Maintenance Planned - Planned New Connection Planned Vegetation Control Subtotal: Total: Table 95 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. 210

213 EVALUATION OF PERFORMANCE Loss of Bulk Supply (Unplanned) 1% Planned Outages 35% Interruption Causes Adverse Environment 1% Adverse Weather 7% Defective Equipment 21% Tree Contact 14% Lightning 1% Human Element 3% Foreign Interference 10% Unknown 11% Unknown 5% Defective Equipment 9% SAIDI Planned Outages 3% Tree Contact 12% Adverse Weather 14% Foreign Interference Human 9% Lightning Element 1% 2% Loss of Bulk Supply (Unplanned) 40% Adverse Environment 1% Unknown 12% SAIFI Planned Outages 3% Loss of Bulk Supply (Unplanned) 24% Tree Contact 14% Lightning 2% Human Element 7% Foreign Interference 11% Adverse Environment 1% Adverse Weather 12% Defective Equipment 14% Figure 78 Interruptions / SAIDI / SAIFI Contribution by Cause

214 SAIDI Minutes EVALUATION OF PERFORMANCE Network SAIDI Performance FY Budget 600 SCI, Regulatory Threshold SAIDI YTD Class B & C After Storm Exemption April May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Figure 79 SAIDI performance trends for FYE 2010 Adverse weather and lightning had most significant impact on network performance with the exception of Planned Outages for FY2010. Top Energy did not breach its reliability threshold value during FYE2010, despite a major event that occurred on 12 th July This storm contributed approximately SAIDI minutes to the annual SAIDI total. The summary of FY2010 network performance before and after the exemption is listed in the table below. FINANCIAL YEAR 2010 YE SAIDI (MINUTES) YE SAIFI Regulatory Quality Threshold Regulatory Quality Threshold Impact of Major Event Days 12 th July Storm Event Total Impact Request for Exemption based on the Guideline Year End Top Energy Performance Pre Exemption Post Exemption SAIDI (mins) SAIFI Below Regulatory Quality Threshold by Below Regulatory Quality Threshold by Table 96 Top Energy Network Performance Summary of Financial Year

215 EVALUATION OF PERFORMANCE In terms of year to date FYE2011, the reliability of supply has continued to show incremental improvement over FYE2009, although the ambitious targets set in the 2010 AMP, which are lower than the Commission s threshold levels, will not be met. Overall, in terms of SAIDI the network has demonstrated an improvement in performance of 9.54 SAIDI minutes or 2.35% 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 FYE10 and FYE11, we have seen an overall 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 2010 / 2011 SAIDI profiles indicates that we have not had the single major storm event within this financial year; rather, we have experienced a more consistent level of storm activity within each month. Although we have had 4 events of a scale that surpassed the storm of July 12th 2009, the overall recorded SAIDI impact for each event has been greatly reduced. For example, Tropical Cyclone Wilma which impacted Northland in January 2011, was reported as the first "tropical cyclone" in recorded history to ever hit New Zealand and it topped off a month that saw two other named tropical storms hit the upper North Island. A WeatherWatch analyst described Wilma as the most significant storm to hit New Zealand in 14 years, surpassing the strength of cyclones Drena, Fergus, Bola and Giselle, which all began as tropical cyclones but reduced in strength and lost their tropical characteristics before making landfall in New Zealand. Wilma resulted in 39 SAIDI minutes and the other three storm events total SAIDI minutes. In comparison, the single event on the 12th July 2010, and much lower in strength, resulted in SAIDI minutes Figure 80 Monthly SAIDI performance trends for FYE 2010 and FYE 2011 Whenever there is the potential for damaging weather conditions to eventuate within the region, TEN receives a series of escalating warnings from the New Zealand Met Service. These warnings begin at a Threat, or Watch status and escalate to Severe Weather Warning and Thunderstorm Warning. It is normal for the division to receive around 20 Threat warnings per year, which can usually be expected to result in 2 major storm events and a single thunderstorm event. Over the course of 2011, this level has dramatically increased. 213

216 EVALUATION OF PERFORMANCE Severe weather watch Severe weather warning Thunder storm Warning SAIDI April May June July August September October November December January Table 97 Top Energy Network Meteorological Warnings FYE2010 and FYE2011 In examining the pattern of storm events, there is a direct correlation between the monthly attributable SAIDI profile and the number of Severe Storm Warning / Thunderstorm Warnings received. In FYE2010, we had a total of 33 warnings, which resulted in 1 major event in July 2009 and 2 minor events in April 2009 and October The recorded warnings / events match the SAIDI profile peaks throughout the year, with all months being below 50 SAIDI with the exception of July 2009 recording just below 200 SAIDI minutes Thunder storm Severe weather warning SAIDI Figure 81 FYE 2010 monthly SAIDI performance against storm warnings However in 2011 so far, we have witnessed: 144 separate Severe Weather Warnings, for 214

217 o o o o 49 individual Severe Weather Events, of which 42 Gale Force Storm events 2 Severe Lightning Storm events 1 Weather bomb the size of Australia on September 17th. EVALUATION OF PERFORMANCE This has resulted in a much flatter, yet consistently elevated SAIDI profile throughout the year, with most months still registering below 50, with the exception of September 2010, October 2010 and January The monthly maximum SAIDI peaks at 88 for January Thunder storm Severe weather warning SAIDI Figure 82 FYE 2011 monthly SAIDI performance against storm warnings When examining the increase that has been seen within the defective equipment category, it has become apparent that this is due, in the main, to a series of outages that have affected the Taipa region and have been attributed to the latent effects of two major thunderstorms that passed through the region in June 2010 and September These storms caused lightning damage to a number of insulators which subsequently failed several months later. Although limited in number, these major faults that affected the 33kV system, under the current network configuration, resulted in a significant customer loss of supply. Whilst storm events have increased, attributable SAIDI as a result of vegetation outages continues to decrease. Benefits are clearly then being seen as a result of the first two years of the increased vegetation control programme, together with the condition based maintenance programme and the network automation project. Top Energy will continue to invest in new technologies and strategies that offer the best mix of performance gains compared to the cost of implementation Reliability by Feeder The following graph ranks Top Energy feeders by their SAIDI and SAIFI performance respectively for year ending 2010 and identify the worst performing feeders for that year. 215

218 EVALUATION OF PERFORMANCE Figure 83 SAIDI performance by feeder Figure 84 SAIFI performance by feeder Top 10 worst feeders are chosen based on the feeder SAIDI performance ranking and with feeder SAIFI performance taken into consideration as well. SAIDI performance has a higher priority than SAIFI for the selection. Nevertheless 6 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. 216

219 EVALUATION OF PERFORMANCE FEEDER NAME SAIDI (CLASS B+C) MINUTES % OF TOTAL SAIDI SAIFI (CLASS B+C) % OF TOTAL SAIFI Table 98 Russell % % Totara North % % Opononi % % South Road % % Rangiahua % % Te Kao % % Oruru % % Purerua % % Herekino % % Oxford Street % % 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: Russell and Opua will be substantially improved by the proposed installation of the new Russell sub-sea cables; Totara North and Purerura, feeders 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 the YE2009 results; Te Kao, Opononi, Herekino and Oxford St feeders will all benefit from 11kV upgrades and the 33kV security of supply work planned. 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 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 FY2010 Information Disclosure: 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 followings: Alpine Energy Eastland Network Electricity Ashburton Horizon Energy Distribution Marlborough Lines Northpower The Lines Company The Power Company 217

220 EVALUATION OF PERFORMANCE MainPower New Zealand The next three figures show that TEN s system reliability index (i.e. SAIDI, SAIFI, and the number of faults per 100km system length) 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) Figure 85 SAIDI for Class B and C Interruptions (FY ) Figure 86 SAIFI for Class B and C Interruptions (FY ) 218

221 EVALUATION OF PERFORMANCE Figure 87 Peer Group Number of Faults per 100km (FY2003-FY2007) The relatively poor level of reliability seen by Top Energy s customers has reinforced Top Energy s intention to spend significantly on projects that will improve reliability Financial Performance The following table shows the financial performance for 2009/10: EXPENDITURE CATEGORY AMP BUDGET 2009/10 ACTUAL SPEND 2009/10 Capital $9,433,000 $8,152,000 Maintenance $5,794,477 $5,998,000 Table expenditure budget compared to actual Capital expenditure finished within 86% 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 2010, although plant and materials had been purchased but not installed. Projects that were rolled into FY2011 included the Waipapa Ground Fault Neutraliser installation, the Mt Pokaka transformer and associated works, the Mt Pokaka double circuit 11kV feeder line and the Ngawha 33kV line. The installation phase of some protection projects will also be completed during FY2011. The committed capital cost of materials for these projects was $900k. During the2009 financial year, a $4m network reliability programme initiative was instigated, involving the installation of over 200 automated isolation devices in strategic locations on the network. The intention of this programme was the reduction of the number of customers affected by each outage, in addition to reducing the switching time associated with each fault event. The programme included: 20 Pole mounted auto-reclosers, 60 Pole mounted SCADA controlloable switches, and 120 Pole mounted auto-sectionalisers. The auto-reclosers were fully operational at the end of the project, however a failure within the recloser remote terminal units was subsequently discovered during an operation in November 2009 which was traced to incorrect settings on the power supply converters pre-installed by the supplier. Replacement parts were ordered during January 2010 and were repaired by the end of March

222 APR MAY JUN JUL AUG SEP OCT NOV DEC JAN FEB MAR MONTHLY EXPENDITURE ('000s) ACCUMULATIVE EXPENDITURE ('000s) EVALUATION OF PERFORMANCE The failure did not affected the auto-reclosers ability to see faults, trip or automatically reclose but did affect the control centre s ability to close the switch remotely after lock-out. The SCADA controllable switches were also installed as manually operable switches during the project, with the intention that once planned communications upgrades had been completed during FYE2010 they would be made remotely operable from the control room.. During FYE 2010 voice and data communications have been separated by installing duplexer units at base repeater stations, thus improving the effectiveness of both channels. As a result of this work, a number of RTUs have been identified as transmitting at a level significantly below operational limits. The most noticeable of this was Channel 1, which was transmitting at less than 1W instead of the 20W that it should have been. A programme for replacement of RTUs was enacted with the intention of full SCADA operability for the switches by the end of March The process of bringing both the auto-reclosers and the SCADA controllable switches on-line, was included within the programme for upgrades in communications planned the FYE2010 financial year. The result of the project has thus far been excellent. Network SAIDI has reduced from over 900 in to 463 in It is expected that as experience with the operation of the devices grows, together with targeted fault handling process improvements, further significant SAIDI / SAIFI improvements will continue to be seen. This programme is now producing significant returns in SAIDI performance savings, with calculated savings of 120 SAIDI minutes for FYE2010. With respect to maintenance costs, the maintenance programme was completed to schedule and within 3% of budget. The overspend of $203k was mainly due to a combination of the July 12 th 2009 storm event, together with an increased spend on high priority defects identified as part of the new condition inspection regimes. TOTAL MAINTENANCE EXPENDITURE $800 $700 $600 $500 $400 $300 $200 $100 $7000 $6000 $5000 $4000 $3000 $2000 $1000 $ $ MONTH Actual Monthly Spend Budgeted Monthly Spend Actual YTD Spend Budgeted YTD Spend Figure 88 Network maintenance expenditure The maintenance initiatives targeted at improving network reliability identified in the 2009 AMP have been successfully undertaken. 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. Maintenance efforts were managed around budget rather than targets. No formal maintenance program was in place as during this period the Geospatial Survey was still in progress. Due to the Geographical Information System not being fully functional it was 220

223 EVALUATION OF PERFORMANCE impractical to attempt to deliver a detailed inspection and maintenance program as there simply was not enough available information. The inspection program was limited to Zone Substation. The remainder of the Network was inspected as a by-product of the Geospatial Survey. Any asset found in a particularly poor state was logged in a spreadsheet and scheduled for remediation. Therefore the short term solution was to focus on faults and hot spotting while systems were implemented. Now the Geospatial Survey is complete Top Energy is nearing completion of its first year 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. The table below schedules progress made in implementing projects identified in the 2009 Top Energy AMP.. REVIEW OF 2009 ASSET MANAGEMENT PLAN Section Project ID Description Start Date Actual Performance Loss Ratio Keep Loss Ratio close to 8% 8.8% Distribution and LV Line Data capture Capture main data Completed. Field verification of conductor type difficult Subtransmission poles kV poles requiring major work Completed Subtransmission poles kV poles requiring minor work Completed Earthing Refurbishment Earth testing and Remediation Rescheduled till TEN kV - TPA - Line - Resource Consent work for Taipa second 33kV line and ground mount switching station Awanui - including purchase of land if required TEN kV - New 110kV line to Waipapa #2 line easements from KOE - WPA 2009 Cancelled due to the review of the capital works programme. This expenditure was replaced by a project of similar value from On going TEN07042 TEN08006 TEN08007 TEN kV - New 110kV line to Waipapa #2 resource consents from KOE - WPA 33kV KER- New substation easements 33kV KER- New substation land 33kV KER- 33kV Overhead line to new substation 2010 On going 2010 On going 2010 On going 2010 Completed TEN06037 SUB - PKN - upgrade of CB's & Protection 2009 Completed 221

224 EVALUATION OF PERFORMANCE REVIEW OF 2009 ASSET MANAGEMENT PLAN Section Project ID Description Start Date Actual Performance TEN06070 SUB - PKN - Install new Security Cameras 2010 Rescheduled till TEN06071 SUB - NPL - Install Security Cameras TEN06068 SUB - OKH - Install new Security Cameras TEN06069 SUB - TPA - Install new Security Cameras TEN06062 SUB - KHE - Install new Security cameras TEN07024 SUB - KWA - New Line protection, NOVA x 2, SEL 351R, VTS x 1, 32, 92 TEN06063 SUB - KWA - Install new Security Cameras 2010 Rescheduled till Rescheduled till Rescheduled till Rescheduled till Completed 2010 Rescheduled till 2012 TEN07065 SUB - KWA - Move transformer unit number (5MVA present, 5MVA capable) from Kawakawa to Moerewa and provide new differential protection Project Superseded TEN07026 SUB - MOE - New Line protection, NOVA x 4, SEL 351R, VTS x 2, 32, 92 TEN06064 SUB - MOE - Install new Security Cameras 2010 completed 2010 Rescheduled till 2012 TEN07025 SUB - MOE - New T2 23 MVA transformer pad as per Okahu substation Project Superseded TEN06011 SUB - MOE - install new Transformer T2, ex KWA T2, including Differential Protection 2009 Project Superseded TEN07070 SUB - MOE - Move transformer unit number (11.5 MVA) from Moerewa to Kaeo and provide differential protection Project Superseded TEN06135 SUB - HAR - New Line protection, NOVA x 2, SEL 351R, VTS x 2, 52, Completed TEN06073 SUB - HAR - Install Ethernet Comms 2010 Completed 222

225 EVALUATION OF PERFORMANCE REVIEW OF 2009 ASSET MANAGEMENT PLAN Section Project ID Description Start Date Actual Performance TEN06061 SUB - HAR - Replace RTU 2010 Completed TEN06067 SUB - HAR - Install new Security Cameras 2010 Rescheduled till TEN06010 SUB - WPA - Replace 2x 11kV incomer breakers & CT's 2010 Completed TEN06014 SUB - WPA - 4x 750kVAr switched capacitor banks 2009 Rescheduled till 2011 TEN06065 SUB - WPA - Install new Security Cameras TEN07002 SUB - KAEO - Fencing, Road access, Planting 2010 Rescheduled till /08 Rescheduled till TEN06059 SUB - OMA - Replace RTU 2009 Completed TEN06066 TEN06058 TEN06145 TEN06093 SUB - OMA - Install new Security Cameras SUB - OMA - Install Ethernet Comms DIST - Purerua Feeder - install switched capacitor DIST - install 6x WE reclosers w/sel351r & RTU 2010 Rescheduled till Completed 2010 Completed 2010 Completed TEN07116 COMM - Channel 1,2,3,4,5,6 second repeaters 2010 Completed Table 100 Progress on implementing projects identified in the 2009 AM plan The above table indicates a reasonable attainment of project targets. Bearing in mind the improved data streams coming available to the Asset Management Team it is not surprising that a number of projects have been reprioritised and new projects have been identified. Furthermore the disruptions caused by the storms have inevitability diverted resources from project work. TEN s response has been to increase the resource available in order to both 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 we are involved with. To that end Top Energy proposes to continue to build on its present knowledge base to refine the options it will pursue to address the multiple, 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: 223

226 EVALUATION OF PERFORMANCE 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. 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 Figure 89 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 PAS-55 Asset Management System Elements 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 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 recognized 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. The PAS-55 framework is shown diagrammatically in figure below. 224

227 EVALUATION OF PERFORMANCE O utside the S cope of P AS 55 E stablish / M aintain O rganisational S trategic P lan w hich m ay include: -Vision, Mission & Values -Policies & Objectives -Organisational Strategy -Identify & Review Stakeholder Requirem ents -C onsider all other relevant internal & external business factors M anagem ent Review Establish / M aintain AM Policy R isk Identification, Assessm ent & Control N ew AM R elated M ethods & T echnologies Establish / M aintain AM Strategy Establish / M aintain AM Objectives E stablish / M aintain AM Inform ation System R isk Identification, Assessm ent & Control E stablish / M aintain Legal, R egulatory and O ther AM Requirem ents P AS 55 Asset M anagem ent S ystem Elem ents E stablish / M aintain AM P erform ance / Condition Targets E stablish / M aintain O ptim ised & P rioritized AM P s Im plem entation & Operation Establish / M aintain: Structure, Authority & Responsibilities Training, Awareness & Com petence Consultation & Com m unication Docum entation Docum ent & Data Control Operational Control Em ergency Preparedness & Response O ptim ising M ethods T ools, techniques & processes Checking, Corrective & Preventive Action Establish / M aintain: P erform ance, C ondition M easurem ent & M onitoring Asset R elated Failures, Incidents, N on C onform ances, C orrective & P reventive Action Records & Records M anagem ent Au dit Figure 90 PAS-55 Asset Management Framework 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. Figure 91 Graphical representation of the Top Energy PAS-55 review results 225

228 EVALUATION OF PERFORMANCE In general, Top Energy is demonstrably weak in several key areas of asset management process control. With the exceptions of Asset Management Plans and Emergency Preparedness, TEN are 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 is therefore necessary in these areas to meet the base line requirements of PAS-55. The AM improvement plan adopted is detailed in the following tables. Of the areas above, progress has already been made in several items by the implementation of the following strategies: a) 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. b) 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. c) 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 the Network division. d) Development of a Policy, Procedure, Standards framework - Although a significant number of Policies, Procedures and Standards have been produced during the course of 2010, Operational, Maintenance and Design standards remain one of the key areas for focused improvement within FYE2012. 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. e) 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. f) Development and implementation of a Training / Competence management strategy A comprehensive Authorisation Holders Certificate (AHC) training and competency management system has been put into place during g) 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. 226

229 h) Improvements in Documentation and Records Management EVALUATION OF PERFORMANCE 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 for the main Document management system. i) 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) j) Development of an Audit and Management Review strategy and process A site safety field audit programme has been initiated by the CEO and is driven by the operational managers within the business. Further developments and continual improvement projects within the PAS 55 scope are planned for FYE 2011 and FYE

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

231 EXPENDITURE FORECAST 9 Expenditure Forecast year forecast of capital and operational expenditure Figure 94 shows the graphical the 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 total budgeted expenditure for FYE11 and total actual expenditure in FYE09 and 10. As can be seen from the graph, there is a significant step change in investment in FYE11, due mainly to increased expenditure on capacity and reliability. This step change has posed significant problems, not least of which the availability of suitable skilled resource from a constrained industry market. Top Energy is continuing a large national campaign to attract this resource to the northern region. 30,000,000 Total Actual 25,000,000 20,000,000 15,000,000 10,000,000 Total Budget Operational Expenditure: Fault and Emergency Maintenance Operational Expenditure: Refurbishment and Renewal Maintenance Operational Expenditure: Routine and Preventative Maintenance Capital Expenditure on Non- System Fixed Assets 5,000,000 Figure year graphical financial forecast summary Capital Expenditure: Asset Relocations Capital Expenditure: Asset Replacement and Renewal Capital Expenditure: Reliability, Safety and Environment The tables below detail the breakdown of expenditure viewed from a regulatory cost category comparison. Where possible, projects were optimised with respect to the required technical constraints followed by a desire to create a fairly flat and consistent work stream for our available technical and core skill resource to ensure both consistency and stability of work across the planning period. 229

232 EXPENDITURE FORECAST YEAR 1 YEAR 2 YEAR 3 YEAR 4 YEAR 5 FOR YEAR ENDED Capital Expenditure: Customer Connection 1,000,000 1,200,000 1,500,000 1,500,000 1,500,000 Capital Expenditure: System Growth 6,686,006 8,389,612 8,179,680 7,725,343 7,580,000 Capital Expenditure: Reliability, Safety and Environment Capital Expenditure: Asset Replacement and Renewal 5,392,500 2,550,000 1,950,000 2,920, ,000 4,085,000 4,045,000 4,085,000 4,045,000 4,085,000 Capital Expenditure: Asset Relocations 175, , , , ,000 Subtotal - Capital Expenditure on asset management 17,338,506 16,409,612 15,964,680 16,440,343 14,150,000 Capital Expenditure on Non-System Fixed Assets 1,250,000 55,125 57,881 60,775 63,814 Operational Expenditure: Routine and Preventative Maintenance Operational Expenditure: Refurbishment and Renewal Maintenance Operational Expenditure: Fault and Emergency Maintenance Subtotal - Operational Expenditure on asset management 4,100,000 2,100,000 2,100,000 2,100,000 2,100,000 1,077, , ,000 1,020,000 1,183, , , , , ,000 6,077,500 3,720,000 3,820,000 4,020,000 4,183,500 Total direct expenditure on distribution network 24,666,006 20,184,737 19,842,561 20,521,118 18,397,314 Table 101 Capital and maintenance expenditure 2011 to 2015 YEAR 6 YEAR 7 YEAR 8 YEAR 9 YEAR 10 FOR YEAR ENDED Capital Expenditure: Customer Connection 1,500,000 1,500,000 1,500,000 1,500,000 1,500,000 Capital Expenditure: System Growth 6,882,316 7,421,280 5,965,012 8,271,912 9,736,264 Capital Expenditure: Reliability, Safety and Environment Capital Expenditure: Asset Replacement and Renewal 1,700,000 1,091, , , ,500 4,045,000 4,085,000 4,045,000 4,085,000 6,365,000 Capital Expenditure: Asset Relocations 250, , , , ,000 Subtotal - Capital Expenditure on asset management 14,377,316 14,347,592 12,319,512 15,130,412 18,223,

233 EXPENDITURE FORECAST YEAR 6 YEAR 7 YEAR 8 YEAR 9 YEAR 10 FOR YEAR ENDED Capital Expenditure on Non-System Fixed Assets 67,005 70,355 73,873 77,566 81,444 Operational Expenditure: Routine and Preventative Maintenance Operational Expenditure: Refurbishment and Renewal Maintenance Operational Expenditure: Fault and Emergency Maintenance Subtotal - Operational Expenditure on asset management 2,100,000 2,100,000 2,100,000 2,100,000 2,100,000 1,102,500 1,282,500 1,410,000 1,520,000 1,745, , , , , ,000 4,102,500 4,282,500 4,410,000 4,520,000 4,745,000 Total direct expenditure on distribution network 18,546,821 18,700,447 16,803,385 19,727,978 23,050,208 Table 102 Capital and maintenance expenditure 2016 to ,000,000 Operational Expenditure: Fault and Emergency Maintenance Operational Expenditure: 25,000,000 Refurbishment and Renewal Maintenance Operational Expenditure: Routine and Preventative 20,000,000 Maintenance Capital Expenditure on Non- System Fixed Assets 15,000,000 Capital Expenditure: Asset Relocations 10,000,000 5,000,000 0 Figure 93 Financial forecast by Commerce Commission category Capital Expenditure: Asset Replacement and Renewal Capital Expenditure: Reliability, Safety and Environment Capital Expenditure: System Growth Capital Expenditure: Customer Connection 231

234 EXPENDITURE FORECAST The OPEX expenditure projection is presented in four high level categories, as follows: Routine and preventative: This category includes vegetation management and planned network maintenance. Examples include, scheduled distribution transformer inspections, cable locating, distribution transformer earth-bank testing, tap changer testing and switchgear maintenance. Operations refurbishment and Renewal. This includes all planned maintenance work involving repairs to the network and which is not capitalised. Examples include tap changer refurbishment, transformer/building painting and other similar activities. Operations Faults: This includes all activities associated with unplanned reactive work on the network and which requires urgent attention. Examples include cable joint and insulator failures. 9.2 Reconciliation of actual expenditure against expenditure for Yr 2010 The following table shows the financial performance for 2009/10: EXPENDITURE CATEGORY AMP BUDGET FYE 2010 ACTUAL SPEND FYE2010 Capital $10,083,250 $8,152,000 Maintenance $5,794,477 $5,998,000 Table 103 FYE2010 expenditure budget compared to actual Capital expenditure finished $1.93M below the AMP budget expenditure for the year, due mainly to a number of distribution projects, which were commenced, but incomplete as of the 31 March Projects that have been continued into FY2011 include: The Waipapa Ground Fault Neutraliser installation, The Mt Pokaka transformer and associated works, The Mt Pokaka double circuit 11kV feeder line, and The Ngawha 33kV line. The installation phase of some protection projects will also be completed during FY2011. With respect to maintenance costs, the year end maintenance expenditure totalled $5.997m, greater than the budget of $5.794m budget by $203k. This was mainly due to a combination of the July storm event, together with an increased spend on high priority defects identified as part of the new condition inspection regimes. In this regard, routine and preventative expenditure was reduced to offset the increase in faults expenditure during the year. Progress for the year ending 2010 against plan was steady, with the majority of maintenance schedules for the new inspection methodology being completed. The programme represented a major step change for both Top Energy Network and Top Energy Contracting Services and the overall result has been pleasing. A small number of maintenance streams however, have been deferred until the new financial year due to resource restrictions in specialist technical services, communications and protection areas. This specialist resource has been diverted from maintenance to complete time critical capital projects such as the Mt Pokaka substation and the southern area protection upgrades. A strategy has been developed to both maximise and strengthen the protection and communications capability within Top Energy over the next 24 months. Other areas of improvement to the maintenance process include transitioning maintenance inspection management to Contracting Services to facilitate flexibility in forward workflow planning and delivery. 232

235 APR MAY JUN JUL AUG SEP OCT NOV DEC JAN FEB MAR MONTHLY EXPENDITURE ('000s) ACCUMULATIVE EXPENDITURE ('000s) EXPENDITURE FORECAST The vegetation programme has achieved significant results this year, with an average of 1400 trees trimmed and removed every month, which has contributed to a 32% reduction in the number of vegetation contact faults from 79 in FYE2009 to 54 in FYE2010. Whilst the programme is continuing to target the worst performing feeders for vegetation faults, a rapid patrol has been carried out to assist in identifying vegetation density priorities across the network. This has resulted in a clear work program for YE2011. TOTAL MAINTENANCE EXPENDITURE $800 $700 $600 $500 $400 $300 $200 $100 $7000 $6000 $5000 $4000 $3000 $2000 $1000 $ $ MONTH Actual Monthly Spend Budgeted Monthly Spend Actual YTD Spend Budgeted YTD Spend Figure 94 Monthly Maintenance Expenditure to budget for Budget Actual Maintenance Category MP - Routine and Preventative Maintenance $4,422,000 $3,965,000 MR - Refurbishment and Renewal Maintenance $1,000,000 1,002,000 F - Fault and Emergency Maintenance $950,000 1,031,000 Total maintenance expenditure on distribution network $5,794,000 $5,998, Significant assumptions The next table records the significant assumptions made in preparing the financial forecasts, the basis for the assumption and the potential impact of the associated uncertainty. 233

236 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 slow down 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 Energy Policy to encourage investment in infrastructure. Uncertainty over the regulatory pricing implications for the coming 5 yr 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 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 generations equitable between transmission and distribution networks. The principal sources of information for developing these 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 234

237 EXPENDITURE FORECAST ISSUE ASSUMPTION BASIS FOR THE ASSUMPTION POTENTIAL IMPACT OF UNCERTAINTY taking customers will not be penalised in a way that cross subsidises the connection of generation. assumptions are: Government policy statements. Electricity Governance Rules Transmission connection charges. Various papers produced by officials. Network studies showing the effects of distributed generation. amount of reactive power would have to be supplied into that point with or without the active power injection, then 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. 235

238 EXPENDITURE FORECAST ISSUE ASSUMPTION BASIS FOR THE ASSUMPTION POTENTIAL IMPACT OF UNCERTAINTY ECONOMIC ACTIVITY It has been assumed that economic activity based on primary production and processing will 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. The network studies have assumed continued development of the area. Different rates have been used 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. If economic activity increases, growth related capital expenditure will increase. If economic activity reduces, the 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. Predictions on primary produce long term forecasts. Predictions on the leisure markets. CUSTOMER Establishment of service levels continue to be through consultation with stakeholders and Performance targets driven by customer consultation indications. This is focussed on determining the It is expected that customers expectations will increase as the quality of supply improves. This means 236

239 EXPENDITURE FORECAST ISSUE ASSUMPTION BASIS FOR THE ASSUMPTION POTENTIAL IMPACT OF UNCERTAINTY EXPECTATIONS remain a balance between customer needs, price-quality tradeoffs and industry best practice. 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. 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: Industry benchmarking which shows our reliability as the worst in the country Customer feedback Complaints Focus groups Customer representatives Other community input. 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. 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. 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 ongoing 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 inputs to significantly alter this plan. The Asset Management Plan includes specific sites and conceptual design detail. 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 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. 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 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 5 years of The projected Asset Replacement and Renewal programme is based upon the known condition and defect information gathered during annual asset Identification of specific asset issues may cause increased expenditure for certain asset classes within future years. i.e. the identification of an inherent 237

240 EXPENDITURE FORECAST ISSUE ASSUMPTION BASIS FOR THE ASSUMPTION POTENTIAL IMPACT OF UNCERTAINTY the planning window. inspections, together with estimated failure rates for assets of a specific age profile. 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 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. (The inflation referred to is that associated with the renewal and construction of distribution networks, not general inflation). Table 104 Significant assumptions related to the financial forecast 238

241 APPENDICIES Section 10 Appendices 10.1 Appendix A Nomenclature Appendix B Typical Zone Substation Arrangements Appendix C 2009 Customer Consultation Survey Questions Appendix D Feeder Load Growth Appendix E Risk Management Framework Risk Management Process Risk Management Context Appendix F- Level of Service Indicators List of Tables List of Figures

242 APPENDICIES 10 Appendices 10.1 Appendix A Nomenclature GENERAL kv kilo-volt ka kilo-ampere kw kilo-watt MVA MW MVAr 1000 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 amperes of current. Fault current is typically measured in ka or its MVA equivalent according to MVA=sqrt3 x kv x ka watts of real power (for example 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 (1000 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. So the generators, 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 (1000 kilo watts) of real power. The quadrature vector component that when vectorially added to real power gives apparent power. ka rms One of the ratings of equipment is square-root of the mean of the squares. 3-phase 3-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 GIS GPS CMMS SCADA 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 RTU s 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. CIRCUIT RELATED OH UG GXP Overhead. Underground. Grid Exit point. A Transpower substation where electricity is stepped down from a voltage of 110kV (the transmission voltage used in Top Energy area) to 33kV and fed to Top Energy s zone substations 240

243 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 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 2 or 3-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 3hours. 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 2 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 3hr 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 sub is out of service. Top Energy sizes its transformers for local load forecast and future envisaged transfer capacity for feeders between a zone sub and its neighbour that a zone sub 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 sub fails, the feeders between it and an adjacent zone sub are picked up by the adjacent zone sub with all of the transformers at the adjacent zone sub operating concurrently. If Top Energy were to cover the event of both a zone sub failing, and one of the transformers at an adjacent zone sub 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 241

244 APPENDICIES used outside of the armour. OTHER EQUIPMENT RELATED ABS Pillar Box or Pillar Air Break Switch. These are manually operated or motorised remote control switches. These switches are used to create 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 customer s premises. RMU 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. Recloser Sectionaliser Circuit Breaker (CB) A (normally) 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 preset 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 Oil Natural, Air Natural (no fans or pumps) ONAF Oil Natural, Air Forced (fans but no pumps) OFAF Oil Forced, Air Forced (fans and pumps) ODAF 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 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 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, and none of the ones for Top Energy have. Outside of major refurbishment occasions, a less invasive method is to indirectly determine DP through analyzing 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 analyzed 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 one being partial discharge analysis. PD 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 242

245 APPENDICIES 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 analyzed, 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 detanking. 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 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 SAIDI: 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 243

246 APPENDICIES 10.2 Appendix B Typical Zone Substation Arrangements Top Energy two transformer zone substations are typically two incoming 33kV circuits with 33kV normally open inter-tie isolators between the two circuits, with 33kV and 11kV CBs either side of each transformer feeding onto a single 11kV bus. The 11kV bus has a tie breaker on it normally run open. There is no bus zone protection. Twin incoming 33kV circuits are typically run unparalleled due to the absence of directional protection. Once this is provided, the circuits will be operated paralleled at the 33kV level and at the 11kV level. An improvement to protection regimes will be required for instance using dual setting protection relays. 11kV air break inter-tie switches are provided just outside the substation to enable certain feeders from either side of the 11kV tie breaker, to be paralleled. 244

247 APPENDICIES 10.3 Appendix C 2009 Customer Consultation Survey Questions The survey asked the following questions. QUESTION Thinking of yourself as an XXX customer, when was the last time your power went off? How would you rate the reliability of your current power supply? 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 3 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) PROMPTS Can t remember, Days ago, Weeks ago, Months ago, Years ago Acceptable, More than acceptable, Unacceptable, More than unacceptable 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 10.4 Appendix D Feeder Load Growth YEAR END FEEDER_NAME SOUTHERN NETWORK KAIKOHE CB0105 Rangiahua CB0106 NRCF CB0107 Kaikohe CB0108 Awarua CB0109 Taheke CB0110 Ohaewai CB0111 Horeke KAWAKAWA CB0206 Towai CB0207 Kawakawa CB0208 Opua CB0210 Russell MOEREWA CB0304 AFFCo CB0305 Tau Block CB0307 Pokapu CB0308 Moerewa WAIPAPA 247

249 APPENDICES YEAR END FEEDER_NAME CB0405 Totara Nth CB0406 Riverview CB0407 Whangaroa CB0408 Purerua CB0409 Aerodrome Rd CB0410 China Clay OMANAIA CB0504 Rawene CB0506 Opononi HARURU CB0606 Te Tii Bay CB0607 Puketona CB0608 Onewhero CB0609 Joyces Rd NORTHERN NETWORK OKAHU CB1105 South Rd CB1106 Kaitaia West CB1107 Redan Rd CB1108 Oxford St CB1109 Herekino CB1110 Pukepoto TAIPA 248

250 APPENDICES YEAR END FEEDER_NAME CB1206 Oruru CB1207 Tokerau CB1208 Mangonui PUKENUI STH CB1305 Te Kao CB1306 Pukenui Sth NPL CB1405 JNL Nth CB1406 Awanui CB1407 JNL CB1408 North Rd CB0149 JNL CB1410 JNL Nth

251 APPENDICES 10.5 Appendix E Risk Management Framework Risk Management Process The adopted WDC risk management process is consistent with Australian/New Zealand standard AS/NZ 4360 (now superceded 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 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 20yrs Occur once every 10yrs Occur once every 5yrs 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 250

252 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 251

253 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). 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. Shareholder flight 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 252

254 APPENDICES 10.6 Appendix F- Service Level Indicator Analysis Top Energy performance measures for which targets are established KEY SERVICE CRITERIA AMP PERFORMANCE MEASURES TARGETS APPLIED RELIABILITY CAPACITY QUALITY CUSTOMER SERVICE ENVIRONMENTAL SAIDI SAIFI CAIDI Customers without Power 24hrs Customers without Power 3hrs Faults/100km total Total Interruptions Security of Supply Levels of service record locations where the firm capacity is currently or forecast to be exceeded for GXP substations, Zone substations, and sub-transmission circuits. Loading on feeders are also measured as a level of service, to identify areas for improvement where loads exceed the reliability design limits Under Voltage / Over Voltage Frequency Harmonics Momentary fluctuations Customer installation problems % of customers satisfied with level of customer service, reliability of supply and quality of supply % of complaints responded to within 2 days % of complaints progress advised within 7 days % of complaints finalised within 40 days Availability of customer phone hotline (24 hours, 7 days) CC communication requirements: Properly advise customers about the price-quality trade offs available to them Consult with customers regarding quality of service and price of the service Properly consider views of customers following consultation above Adequately take customer views into account during asset management decisions Number of complaints of excessive noise from substation/distribution transformers Number of environmental complaints from customers/public Yes Yes No Yes Yes No No Yes Targets are applied at substation level within the Security of Supply standard, however this cannot be applied at 110kV for the Northern Network and is reliant on Embedded Generation on the Northern and Southern Networks. At 33kV level, restoration of supplies cannot be achieved in line with the standard under the current configuration of the Network. No Not Included No No Not Included No specific targets applied Not included Not included Not Included Not Included No specific targets applied Not included Yes No No Not included Not included 253

255 APPENDICES KEY SERVICE CRITERIA AMP PERFORMANCE MEASURES TARGETS APPLIED SF6 Gas Lost (as a percentage of total volume) Number of uncontained Oil Spills Number of identified environmental problems Not included Not included Not included ECONOMIC EFFICIENCY SAFETY Load factor Capacity Utilisation factor Loss ratio Direct cost per km Indirect cost per customer. Cost per kwh $ Connection cost per customer Number of public injuries at TEN facilities or due to TEN sub-transmission and distribution circuits Number of OSH notifiable accidents Number of Employee injuries No Discussion, but no detailed figures or targets Discussion, but no future targets No Yes No No No No No 254

256 APPENDICES 10.7 Appendix G - 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 Res ource 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 Ma nager

257 APPENDICES 10.8 List of Tables Table 1 Network Summary (as at 31 March 2011 unless otherwise shown)... 9 Table 2 Optimised Deprival Valuation (ODV) summary as at 2004* Table 3 Top Energy zone substation uneconomic feeder statistics Table 4 Causes of unplanned interruptions Table 5 FY2010 network performance Table 6 Breakdown of line faults Table 7 Service Level targets Table 8 Major capital project timeline Table 9 Expenditure Forecast Breakdown FYE Table 10 Network parameters (as of 31 March 2011 unless otherwise shown) Table 11 Relationship between Stakeholders and AM Plan Table 12 Top Energy Network division levels of delegation Table 13 Top Energy order approval levels Table 14 Present Zone Substation Transformers Table 15 Present Zone Substation Transfer/Switching Capabilities Table 16 Distribution Transformer Population Table 17 Uneconomic lines Table 18 ODV summary as at Table 19 Power transformers installed at zone substations Table 20 Type and location of 11kV circuit breakers Table 21 Age profile of substation buildings Table 22 Customer service levels Table 23 Breakdown of line faults Table 24 Loss Ratio Target Levels Table 25 Financial Service levels Table 26 Customer survey Table 27 Customer expectations - SAIDI Table 28 Customer expectations - SAIFI Table 29 Network performance targets compared with the peer group Table 30 Expenditure Forecast Table 31 Top Energy Security Standard Table 32 Zone Substation Transformer backup and Timings Table 33 Top Energy Design Capacity Limits Table 34 Zone Substation Maximum Demand (MVA) Table 35 Top Energy Individual Zone Substation Security Table 36 Capacity Comparisons Table 37 Distributed generation connection process Table 38 Emergency Load Shedding Specification Table 39 Top Energy Emergency Load Shedding Feeder Identification

258 APPENDICES Table 40 Top Energy Published Target levels for Security of Supply Table 41 Major Project Implementation Timeline Table kV/33kV line projects Table 43 Wiroa substation projects Table 44 Okahu Rd substation projects Table 45 Pukenui substation projects Table 46 Taipa substation projects Table 47 NPL substation projects Table 48 Kaikohe substation projects Table 49 Kawakawa substation projects Table 50 Moerewa substation projects Table 51 Haruru Falls substation projects Table 52 Waipapa substation projects Table 53 Omania substation projects Table 54 Proposed Kaeo substation projects Table 55 Proposed Kerikeri substation projects Table 56 Proposed Purerua substation projects Table 57 Pukenui substation distribution projects Table 58 Okahu Rd substation distribution projects Table 59 Taipa substation distribution projects Table 60 Kaikohe substation distribution projects Table 61 Kawakawa substation distribution projects Table 62 Moerewa substation distribution projects Table 63 Haruru Falls substation distribution projects Table 64 Waipapa substation distribution projects Table 65 Omanaia substation distribution projects Table 66 Network wide projects b) Table 67 TEN asset inspection programme Table 68 Response priority definitions Table 69 Life Cycle Expenditure Forecast OH conductors Table 70 Life Cycle Expenditure Forecast poles and structures Table 71 Life Cycle Expenditure Forecast Underground & Submarine Cables Table 72 Life Cycle Expenditure Forecast Distribution & SWER Transformers Table 73 Life Cycle Expenditure Forecast Auto-Reclosers Table 74 Life Cycle Expenditure Forecast Regulators Table 75 Life Cycle Expenditure Forecast Ring Main Units Table 76 Life Cycle Expenditure Forecast Sectionalisers Table 77 Life Cycle Expenditure Forecast Capacitors Table 78 Life Cycle Expenditure Forecast Zone Substation Transformers Table 79 Life Cycle Expenditure Forecast Circuit Breakers Table 80 Life Cycle Expenditure Forecast Zone Substation Structures Table 81 Life Cycle Expenditure Forecast Zone Substation DC Systems

259 APPENDICES Table 82 Life Cycle Expenditure Forecast Zone Substation Protection Table 83 Life Cycle Expenditure Forecast Zone Substation Grounds & Buildings Table 84 Life Cycle Expenditure Forecast Customer Service Pillars Table 85 Life Cycle Expenditure Forecast Earth Installations Table 86 Life Cycle Expenditure Forecast SCADA and Communications Table 87 Life Cycle Expenditure Forecast Load Control Plant Table 88 Maintenance Driven Expenditure by Commerce Commission Category Table 89 Breakdown of Maintenance Driven Operational Expenditure Table 90 Risk management review and reporting cycle Table 91 Risk process main elements Table 92 Top ten risks identified Table 93 Network reliability performance Table 94 Network reliability performance Table 95 Network reliability statistics Table 96 Top Energy Network Performance Summary of Financial Year Table 97 Top Energy Network Meteorological Warnings FYE2010 and FYE Table 98 Top ten worst ranking feeders Table expenditure budget compared to actual Table 100 Progress on implementing projects identified in the 2009 AM plan Table 101 Capital and maintenance expenditure 2011 to Table 102 Capital and maintenance expenditure 2016 to Table 103 FYE2010 expenditure budget compared to actual Table 104 Significant assumptions related to the financial forecast

260 APPENDICES 10.9 List of Figures Figure 1 Top Energy Sub-transmission lines (33kV) and transmission Transpower (110kV)... 9 Figure 2 Map of uneconomic lines Figure 3 Historical and YE2010 SAIDI performance Figure 4 Historical and YE2010 SAIFI performance Figure 5 Network architecture 1 st April Figure 6 Completed Architecture 1 st April 2035 (forecast) Figure 7 Expenditure Forecast (FYE2012 to FYE2021) Figure 8 FYE2010 Regulated electricity lines business return on investment Figure 9 FYE2010 Regulated electricity lines business: Annual Line Charges per ICP Figure 10 Top Energy Asset Management Document Plan Relationships Figure 11 Top Energy Group structure Figure 12 Top Energy Network Division - Section Structure Figure 13 Maintenance planning information flows Figure 14 Screenshot of the Faults Whiteboard Figure 15 Top Energy area of supply Figure 16 Monthly peak MW Figure 17 Southern 11kV Feeder Load Profiles Figure 18 Northern 11kV Feeder Load Profiles Figure 19 Sub-transmission Feeder Load Profiles Figure 20 Geographic diagram of the Pukenui zone substation Figure 21 Geographic diagram of the Taipa zone substation Figure 22 Geographic diagram of the NPL zone substation Figure 23 Geographic diagram of the 33kV Okahu Road zone substation Figure 24 Geographic diagram of the Kaikohe zone substation Figure 25 Geographic diagram of the Waipapa zone substation Figure 26 Geographic diagram of the Haruru zone substation Figure 27 Geographic diagram of the Kawakawa zone substation Figure 28 Geographic diagram of the Omanaia zone substation Figure 29 Geographic diagram of the Moerewa zone substation Figure 30 Map showing uneconomic lines Figure 31 Age profile of sub-transmission overhead conductors Figure 32 Age profile of distribution overhead conductors Figure 33 Age profile of low voltage overhead conductors Figure 34 Age profile of sub-transmission poles Figure 35 Age profile of distribution poles Figure 36 Age profile of low voltage poles Figure 37 Age profile of distribution underground cables Figure 38 Age profile of low voltage cables Figure 39 Age profile of distribution transformers (all voltages)

261 APPENDICES Figure 40 Age profile of SWER isolating transformers Figure 41 Age profile of reclosers Figure 42 Age profile of regulators Figure 43 Age profile of ring main units a. Figure 44 Age profile of sectionalisers Figure 45 Age profile of capacitors Figure 46 Age profile of power transformers Figure 47 Age profile of sub-transmission circuit breakers Figure 48: Age profile of distribution voltage circuit breakers Figure 49 Age profile of batteries and chargers Figure 50 Age profile of customer service pillars Figure 51 Repeater tower sites Figure 52 Conductor transmission capacity Vs distance Figure 53 Historical and forecasted YE 2010 SAIDI performance Figure 54 Historical with forecasted YE 2010 SAIFI performance Figure 55 Loss Ratios of Top Energy since Figure 56 Expenditure Forecast (FYE2012 to FYE2021) Figure 57 Network Performance Scorecard Figure 58 Example of Network Prioritisation Matrix Figure 59 Percentage of CAGR for 20 years Figure 60 Regional after Diversity Maximum Demand Growth Profile ( ) Figure 61 Southern Network ZS % CAGR ( ) Figure 62 Northern Network Zone Substation percentage of CAGR ( ) Figure 63 Southern Network Feeder Percentage of CAGR ( ) Figure 64 Northern network Feeder percentage of CAGR ( ) Figure 65 Kaitaia Grid Exit Point Load Growth Figure 66 Kaikohe Grid Exit Point Feeder Load Growth Figure 67 Kaikohe Grid Exit Point Load Growth Figure 68 Weak Areas of the Network Figure 69 Ngawha to Kaikohe connection arrangement Figure kV system configuration Figure kV system configuration Figure 72 Maintenance Expenditure Forecast Figure 73 Information flow chart condition based assessment Figure 74 Vegetation Interruption Count Figure 75 Vegetation interruption count per feeder/33kv line Figure 76 Information Flow Vegetation Control Figure 77 Information flow chart earth testing and remediation Figure 78 Top Energy risk management process Figure 79 Top Energy s Lost Time Injury Frequency Rate (LTIFR) Figure 80 Interruptions / SAIDI / SAIFI Contribution by Cause Figure 81 SAIDI performance trends for FYE

262 APPENDICES Figure 82 Monthly SAIDI performance trends for FYE 2010 and FYE Figure 83 FYE 2010 monthly SAIDI performance against storm warnings Figure 84 FYE 2011 monthly SAIDI performance against storm warnings Figure 85 SAIDI performance by feeder Figure 86 SAIFI performance by feeder Figure 87 SAIDI for Class B and C Interruptions (FY ) Figure 88 SAIFI for Class B and C Interruptions (FY ) Figure 89 Peer Group Number of Faults per 100km (FY2003-FY2007) Figure 90 Network maintenance expenditure Figure 91 PAS-55 Asset Management System Elements Figure 92 PAS-55 Asset Management Framework Figure 93 Graphical representation of the Top Energy PAS-55 review results Figure year graphical financial forecast summary Figure 95 Financial forecast by Commerce Commission category Figure 96 Monthly Maintenance Expenditure to budget for

263 Top Energy Limited Station Road, Kaikohe PO Box 43, Kerikeri 0245 New Zealand