INFORMATION DISCLOSURE ASSET MANAGEMENT PLAN ELECTRICITY NETWORK 2003 – 2012

June 2002 Disclaimer: This document has been prepared to comply with the Electricity (Information Disclosure) Regulations 1999. The information in this document has been prepared in good faith and represents Powerco Limited’s intentions and opinions at the date of issue. Powerco Limited does not give any assurance, either express or implied, about the accuracy of the information or whether Powerco Limited will actually implement the plan or undertake any work mentioned in the documents. None of Powerco Limited, it directors, officers, shareholders or representatives accepts any liability whatsoever by reason of, or in connection with, any information in this document or any actual or purported reliance on it by any person. Powerco Limited may change any information in this document at any time. Section Subject Date of Issue Page TOC Table of Contents 30/06/02 3

Contents

1. Executive Summary...... 6 1.1 Purpose of the Plan ...... 6 1.2 Period Covered ...... 6 1.3 Asset Management Performance Drivers and Stakeholders...... 6 1.4 Asset Information Systems ...... 7 1.5 Asset Description ...... 7 1.6 Performance Level Objectives ...... 9 1.7 Lifecycle Maintenance and Development Plans ...... 9 1.8 Risk Management...... 10 1.9 Performance Measurement, Evaluation and Improvement...... 10 2. Key Definitions ...... 11 3. Background and Objectives ...... 14 3.1 About this Plan...... 14 3.2 Period Covered by the Plan...... 14 3.3 Interaction with Corporate Planning and Objectives ...... 14 3.4 Future Review of this Plan...... 14 3.5 Asset Management Overview and Key Drivers ...... 14 3.5.1 Purpose of Asset Management...... 14 3.5.2 Asset Management Performance Drivers...... 14 3.5.3 Stakeholder Interests in the Asset Management Process...... 15 3.6 Responsibilities and Accountabilities for Asset Management ...... 16 3.6.1 Powerco Company Structure...... 16 3.6.2 Asset Management Responsibilities at Powerco...... 16 3.6.3 Asset Management Reporting...... 17 3.7 Asset Management Information Systems ...... 18 3.7.1 Geographical Information System (GIS)...... 18 3.7.2 Zone Substation Asset Register ...... 18 3.7.3 Maintenance and Works Management System...... 18 3.7.4 Ancillary Databases & Financial System...... 19 3.7.5 Manual Record Systems ...... 19 3.7.6 Drawing Management System...... 19 3.7.7 Information Integrity and Improvement Actions ...... 19 4. Details of the Assets ...... 20 4.1 Infrastructure Assets ...... 20 4.2 Subtransmission System Configuration...... 20 4.3 Zone Substation Configuration...... 21 4.4 Distribution Network Configuration...... 22 4.4.1 Central Business District Network Configuration ...... 22 4.4.2 Urban Network Configuration...... 22 4.4.3 Industrial And Commercial Consumer Network Configuration...... 22 4.4.4 Rural Network Configuration...... 22 4.4.5 Remote Rural Network Configuration ...... 23 4.5 Justification for Assets ...... 23 4.5.1 General...... 23 4.5.2 Subtransmission Assets ...... 23 4.5.3 Zone Substation Assets...... 23 4.5.4 High Voltage Distribution Assets ...... 23 4.5.5 Distribution Substation Assets ...... 23 4.5.6 400V Distribution Assets ...... 24 4.5.7 SCADA and Communication Assets...... 24 4.6 The Assets By Category, Age and Condition...... 24 4.6.1 Assets Categories ...... 24 4.6.2 The Assets By Age...... 24 4.6.3 Asset Condition...... 26 5. Performance Levels ...... 28 5.1 Introduction...... 28 5.2 Target Levels of Consumer Service (Service Performance)...... 28 5.2.1 Overview ...... 28 5.2.2 Definition of Consumer Service and Service Performance...... 28 5.2.3 Reliability Targets ...... 29 5.2.4 Capacity Targets ...... 30 5.2.5 Quality Targets ...... 30 5.3 Target Levels for Additional Service Performance Elements ...... 31 5.3.1 Targeted Number of Faults per km of line...... 31 5.3.2 Number of Interruptions ...... 31 5.4 Target Performance f or Economic Efficiency ...... 31 5.4.1 Integration of Economic Efficiency Drivers into Asset Management...... 32 5.4.2 Asset Efficiency Performance Targets...... 33 5.4.3 Asset Utilisation Performance Targets ...... 34 5.4.4 Direct Cost Performance Targets ...... 34 5.5 Target Performance for Safety ...... 34 5.6 Target Performance for Environmental Responsibility ...... 35 5.7 Risk Management...... 35 6. Network Development and Lifecycle Asset Management Plan ...... 36 6.1 Introduction...... 36 6.2 Planning Criteria – Long Term Subtransmission Planning...... 36

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6.2.1 Security Of Supply Standards ...... 36 6.3 Planning Criteria – Medium Term Planning (Distribution Planning) ...... 37 6.3.1 General Feeder Loading Principles...... 37 6.3.2 Underground vs. Overhead Construction...... 38 6.3.3 Feeder Configuration...... 38 6.4 Load Demand Forecast...... 38 6.4.1 The Forecast...... 38 6.5 Non-Asset Solutions...... 43 6.6 Adoption of New Technology ...... 43 6.7 Acquisition of New Assets ...... 43 6.8 Redeployment, Upgrade and Disposal of Existing Assets...... 43 6.9 Long Term Development Plan (Subtransmission Development Plan)...... 44 6.9.1 Introduction...... 44 6.9.2 Planning Period...... 44 6.9.3 Assessment of Suitability of System For Present Needs and Analysis of Development Options ...... 44 6.9.4 Analysis Notes and Consideration of Alternatives ...... 53 6.9.5 Zone Substation Configurations And Capacities – Development Summary...... 53 6.9.6 Summary of Subtransmission System Development...... 54 6.9.7 SCADA and Communication Network Development...... 54 6.10 Distribution System Development (Medium Term Development Plan)...... 55 6.10.1 Introduction...... 55 6.10.2 Planning Period...... 56 6.10.3 Assessment of Suitability of System For Present Needs And Analysis of Development Options...... 56 6.11 Lifecycle Asset Plan (Maintenance and Renewal Plan)...... 56 6.11.1 Introduction...... 56 6.11.2 Maintenance Methodology ...... 57 6.11.3 Scheduling Maintenance and Renewal Activities...... 58 6.11.4 Individual Asset Lifecycle Maintenance Plans...... 59 6.11.5 Asset Renewal Plans ...... 61 6.12 Development, Renewal and Maintenance Ex penditure Forecasts ...... 66 6.12.1 Introduction...... 66 6.12.2 Expenditure Forecasts...... 66 6.12.3 Development Expenditure Forecast...... 67 6.12.4 Renewal Expenditure Forecast...... 67 6.12.5 Operating and Maintenance Expenditure Forecast...... 68 6.13 Outsourcing of Development, Renewal and Maintenance Activities...... 68 6.13.1 Introduction...... 68 6.13.2 Powerco Outsourcing Policy Overview ...... 68 6.13.3 Summary of Partnership Agreements and Contracts ...... 69 7. Risk Management...... 70 7.1 Risk Management Charter...... 70 7.2 Risk Management Plans ...... 70 7.3 Risk Management Process ...... 70 7.3.1 Purpose...... 70 7.3.2 Scope ...... 70 7.3.3 Risk Management Procedure: Review of Maintenance Methodology ...... 70 7.3.4 Risk Management Procedure: Review of Development Planning Criteria...... 71 7.3.5 Risk Management Procedure: Project Prioritisation...... 71 7.3.6 Summary of Contingency Plans and Emergency Response Systems ...... 72 7.4 Conclusions from Risk Analysis ...... 73 8. Performance Measurement and Review ...... 74 8.1 Introduction...... 74 8.2 Review of Previous Plans ...... 74 8.2.1 General Review Comments ...... 74 8.2.2 Review Work In Progress ...... 74 8.3 Review of Service Performance Against Targets ...... 74 8.3.1 System Reliability Performance...... 74 8.3.2 Regional Reliability Performance...... 76 8.3.3 Distribution Feeder Class Reliability Performance...... 76 8.3.4 System Capacity Performance...... 79 8.3.5 System Quality Performance...... 79 8.4 Review of Economic Efficiency Performance Against Targets ...... 80 8.4.1 Asset Efficiency Performance...... 80 8.4.2 Asset Utilisation Performance...... 81 8.4.3 Cost Performance...... 82 8.5 Review of Safety Performance...... 82 8.6 Review of Environmental Performance...... 82 8.7 Review of Physical Performance Against Plan ...... 82 8.8 Review of Financial Progress Against Plan ...... 83 8.9 Improvement Initiatives...... 84 8.9.1 Network Improvement Sub-process...... 84 8.9.2 Summary of Improvement Initiatives Undertaken in 2002...... 84 8.9.3 Future Improvement Strategies ...... 84 Appendix 1: Excerpts from Risk Management Charter...... 86 Background...... 86 Risk Management Policy...... 87 Risk Management Overview ...... 88 Objectives ...... 88 Benefits of Effective Risk Management...... 88

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Process...... 88 Main Elements ...... 89 Plans, Monitoring and Reporting ...... 90 Audit Committee ...... 90 Approval...... 90 Quarterly Management Review ...... 91 Reporting...... 91 Six Monthly Reviews...... 91 Review and Reporting Cycle ...... 92 Consolidated Monthly Reporting...... 92 Risk Priority ...... 92 Risk Register...... 92 Business Risk Map ...... 93 Appendix 2: Powerco Regional Network Area Maps ...... 95

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1. Executive Summary

1.1 Purpose of the Plan Powerco’s electricity system assets range in age from new to 50 plus years. The management of these assets is critical to Powerco providing an efficient and effective service to its consumers. This asset management plan intends to demonstrate responsible management of the electricity system assets by Powerco on behalf of its customers and shareholders.

A fundamental requirement of effective development and management of an electricity network is effective network planning. The Asset Management Plan (AMP) is the documented output of effective network planning and provides short and long range planning direction for network development, renewal and maintenance.

The objective of the Asset Management Plan and the asset management process is to ensure that the needs of all stakeholders are properly considered and incorporated into the long term development, maintenance and operating strategies, and to ensure that the plans prepared provide the optimum balance between the level of service and economic efficiency (asset investment/utilisation and maintenance and operating costs).

The Asset Management Plan is a key input into the corporate planning process. Conversely, key corporate objectives influence the direction of the asset management process.

1.2 Period Covered The Asset Management Plan covers a period of ten years from the financial year beginning on 1 April 2002 (the 2003 financial year) until the year ending 31 March 2012. The main focus of analysis is the first three to five years. Beyond this general forecasts are made which are reviewed annually.

This plan will be reviewed annually with the next plan due for release on 30 June 2003.

1.3 Asset Management Performance Drivers and Stakeholders The primary purpose of the asset management process at Powerco is to deliver the required level of service in an economically efficient manner that meets the needs of the stakeholders. A balancing of the key drivers is required to achieve this purpose.

A summary of the key asset management drivers is given below:

Service performance is the delivery of “electricity line function” service. The key elements of service in this context are: · Reliability of supply: The factors that drive reliability are explained in more detail in section 5. · Capacity of supply: This is described as the ability of the network to supply the load required. · Quality of the supply: This is described in terms of voltage level, waveform quality and momentary fluctuations.

Economic efficiency: The delivery of the service through the best use of capital and other resources, considering the opportunity cost of performing the activity. The key factors that drive economic efficiency are: · Asset investment: The level of capital investment in the assets to deliver the service. The key performance driver in the asset management context is the level of asset utilisation. · Cost: In this context the overhead, operating and maintenance costs associated with the assets.

Safety, environmental responsibility and risk management are important drivers to maintain long term value (to shareholders) and integrity of the network.

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Productivity and commercial efficiency: The delivery of the “asset management” service in a productive/efficient and commercially prudent manner. This is an inherent driver that has been separated out for clarify and focus.

To deliver on the primary purpose of asset management, the asset manager needs to balance service, cost and asset investment to best meet the stakeholder needs.

The figure below illustrates the relationship between the main stakeholders and drivers and the asset management process.

Figure 1: The Asset Management Process Overview and Key Drivers

1.4 Asset Information Systems Asset management information systems have been developed at Powerco to support the asset management processes. The information system consists of the following main systems: · Geonet Geographical Information System (GIS). Powerco operates a GIS for the management of spatial asset information. The GIS contains spatial and attribute information on the distribution and subtransmission assets. · Mainsaver Maintenance and WMS Work Management System. These are used to schedule maintenance activities, manage defect repairs and planned work on the network. · Supervisory Control and Data Acquisition System (SCADA). This provides remote alarm, indication and operating facilities for the network, and collects network load and configuration data. · ENS Electrical Network System. This contains transformer information and installation connection point (ICP) data. · Ancillary databases for control and issuing of installation connection point (ICP) information to retailers and to control manual drawing and documents. · Manual Records; several manual recording systems are maintained, these include: zone substation drawings, equipment operating and service manuals, manual maintenance records, network operating information and policy documentation.

The Network Information System Strategic Plan (NISSP) contains the strategic direction and proposed projects for asset management information systems.

1.5 Asset Description For the purposes of this plan the assets covered are the electricity infrastructure assets, these are defined to include all network fixed assets, sub-transmission system, zone substations, high voltage distribution systems, distribution substations and transformers, low voltage (LV) distribution systems including consumer service connections, SCADA and communication systems. Excluded from the infrastructure assets are land and buildings except zone substation buildings, consumer revenue meters and load control relays which are currently owned by Energy Retailers, non-system fixed assets such as motor vehicles, furniture and office equipment, plant, tools, etc, net financial assets, stores and spares.

Powerco has an extensive urban and rural network serving Taranaki, Wanganui, Rangitikei, Manawatu, Tararua and Wairarapa regions.

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The network comprises a 33 kV subtransmission system supplying sixty three 33/11 kV zone substations from which 11 kV, 22 kV or 6.6 kV feeders radiate throughout the service area. Powerco takes supply from Transpower at 17 grid exit points at 33 kV or 11 kV, and from four hydro stations and two wind farms owned by generating companies.

Zone substation transformer sizes vary from 1.25 MVA to 24 MVA. Substations supplying urban/industrial loads typically consist of two transformer banks, two incoming 33kV feeders supplying the substation, and anywhere between 4 and 15 outgoing 11kV feeders.

The 11kV network in the New Plymouth, Wanganui, Palmerston North and Masterton Central Business Districts consist of highly interconnected radial feeders and the 400V system consists of radial circuits with a high degree of interconnection.

Both high voltage and 400V urban distribution networks are interconnected radial systems. The level of interconnection is moderate, commensurate with reliability requirements. The network configuration for large industrial consumers is commensurate with the nature of the consumer’s operation and capacity demand.

The rural network consists mainly of distribution voltage networks with isolators installed every few kilometres. Some interconnection between feeders is present to allow backfeeding in maintenance and fault situations. Typically, around 70-80% of the feeder load can be supplied by backfeeding from adjacent feeders.

The remote rural feeders are radial with limited interconnection between adjacent feeders.

The condition of all infrastructure assets is maintained to a level commensurate with the nature of the asset, the environmental conditions and the consumers’ reliability requirements.

The average age of the distribution network is around 23 years. Table 1 summarises the average standard life and average age for different asset categories. An average standard life is given for each asset category as there are assets with different standard lives included in the general asset categories.

Table 1: Average Age of Assets Asset Category Average Average Age at Standard Life 31/03/02 Distribution Transformer 45 21 Underground Cable 65 25 Overhead Line 57 27 Zone Substation Assets 43 22 Subtransmission & Distribution Switchgear 37 24

The age profile for the entire infrastructure asset is given in the graph below:

$40,000 Substations $35,000 Switches Transformers $30,000 Cable Overhead Line

$25,000

$20,000

$15,000

$10,000 Replacement Cost ($000)

$5,000

$0 1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 49 51 53 55 57 59 61 63 65 67 69 71 73 75 77 79 Age (Years) Figure 2: Total Asset Replacement Cost vs Age Profile

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1.6 Performance Level Objectives The specific target levels of service chosen are based on a balance of past practice, economic factors, recognised international best practice, and safety considerations. These criteria have been refined over recent years to reflect the direction indicated by government reviews involving all facets of the industry, consumer groupings, and individual submissions, conducted during the recent industry restructuring process. In setting these criteria Powerco believes it achieves an appropriate balance between legislative, regulatory, shareholder requirements and consumer expectations.

For the purpose of this plan, it is assumed that so far as receiving a supply of electricity is concerned, the consumer’s general needs will be satisfied if Powerco meets its Service Performance targets. Service Performance is defined as:

“Delivery of electricity line function services to meet consumer load requirements within targeted quality limits, and within targeted levels of reliability”.

The values set for the reliability indicators SAIDI, CAIDI and SAIFI are given in Table 2 below:

Table 2: Reliability Performance Targets SAIFI (B+C) SAIDI (B+C) CAIDI (B+C) 1.9 98 53

The economic efficiency driver is arguably the most significant of all asset management driver and consideration and balance between service and economic efficiency (asset investment/utilisation and maintenance and operating costs) needs to be considered in asset management decision making.

1.7 Lifecycle Maintenance and Development Plans This AMP describes the plans for network development, maintenance management, reliability assessment, and associated lifecycle management processes for the network asset.

Development of the subtransmission network, distribution network and 400V distribution network over the planning period is determined from the asset management drivers, planning criteria for long term (subtransmission), medium term planning (distribution) and forecast load growth. Where drivers or planning criteria in any areas are not satisfied, development options are considered and programmed where required. Specific development plans have been prepared for the respective medium and long term planning periods.

Powerco’s maintenance policy is based on implementing maintenance that balances the cost of repair and replacement against the consequences of failure. The maintenance planning process used determines the most cost-effective maintenance method for reducing the risk associated with the asset achieving the required level of performance.

Powerco’s maintenance work comprises the following elements: · Routine inspections and condition monitoring · Routine servicing · Evaluation of inspection and condition monitoring results to determine any maintenance · Evaluating faults to predict maintenance requirements · Performing maintenance (repairs, refurbishment or replacement).

Individual asset maintenance plans are prepared for each asset type from which the schedules for maintenance and replacement of the network assets are derived.

The forecast expenditure, including both development and maintenance, over the upcoming years is given in Table 3 on the following page:

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Table 3: Total Asset Management Expenditure Summary Expenditure Class 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Capital 18,729 20,407 21,504 22,205 23,009 23,619 24,332 25,251 25,972 26,491 Operation & Maintenance 14,085 14,226 14,368 14,512 14,657 14,803 14,952 15,101 15,252 15,405 Sub Total 32,814 34,633 35,872 36,717 37,666 38,422 39,284 40,352 41,224 41,896 Asset & Network Management 7,482 7,332 7,369 7,406 7,443 7,480 7,518 7,555 7,593 7,631 Total 40,296 41,965 43,241 44,123 45,109 45,903 46,801 47,907 48,817 49,527

1.8 Risk Management Risk management is an important driver in the asset management process. The purpose of risk management in this context is to manage risks that may prevent the infrastructure assets from meeting consumer service targets, causing harm to people or financial loss to Powerco. “Manage risks” may mean to reduce, eliminate, transfer or accept the risk. Section 7 describes Powerco’s risk management process in detail.

1.9 Performance Measurement, Evaluation and Improvement Powerco’s overall system reliability performance as measured by SAIDI was below target (130 actual compared to a target of 100), however the performance was in the good performing category when compared to the 2001 industry performance. In summary, the performance target was not achieved due to a number of factors: · The 2001 mid-winter storms experienced in the northern Manawatu, Taihape and South Taranaki regions. · The higher than normal amount of lightning activity in the Taranaki region. · A number of protection related zone-substation outages. · The performance of less than five “rouge” feeders that experience ongoing poor reliability performance. · Higher than forecast level of work being performed “dead line” rather than “live line”. · A high number of third party interference, vehicles hitting poles and diggers hitting 11kV feeder cables.

In terms of Powerco’s economic efficiency performance, Powerco’s asset efficiency performance compared well against target for 2002. Powerco’s ODRC/ICP of $2,390/ICP compares well against the industry average ODV/ICP of $2919/ICP (2001 information iisclosure).

Asset utilisation is a key driver of long term asset efficiency. Powerco performance was good when compared to the targets set. The load factor and substation transformer utilisation were in the good performing range when compared to national and international benchmarks.

Powerco’s direct cost performance for 2002 was $998/km which was close to target of $991/km (0.7% variance). Powerco is in the good performing category when compared to the industry where the industry average direct costs per km is $1,165/km (2001 information disclosure).

Both physical and financial progress performed well against plan. Physical progress was 94% complete for capital work and 98% complete for maintenance work.

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2. Key Definitions Adequacy means the ability of the electrical power system to meet the load demands under various steady state system conditions whilst not exceeding component ratings and voltage limits.

Availability means the fraction of time a component is able to operate as intended, either expressed as real fraction, or as hours per year.

CAIDI (Consumer Average Interruption Duration Index) means the average duration of an interruption of supply per consumer who experienced an interruption in the period under consideration. The classes of CAIDI are: class A is Transpower planned outages; class B is Powerco planned outages; class C is Powerco unplanned outages; and class D is Transpower unplanned outages. CAIDI is measured in minutes/interruption.

Capital Expenditure (Capex) means the expenditure used to create new assets or to increase the service performance or service potential of an existing asset beyond the original design service performance or service potential. Capex increases the value of the asset stock, and is capitalised in accounting terms. It is subdivided into two classes, development expenditure and renewal expenditure as described below.

Class Capacity means the capacity of the lowest rated incoming supply to a substation plus the capacity that can be transferred to alternative supplies on the distribution network within the required timeframe.

Consumer means an entity that receives electricity supply through a connection to Powerco’s network. The term is readily interchangeable with “customer”.

Contingency means the state of a system in which one or more primary components are on outage. The level of a contingency is determined by the number of primary components on outage. A "k-Level'' contingency is thus the state of a system in which exactly k primary components are on outage.

Cyclic Loading defined in IEC 354 means loading with cyclic variations (the duration of the cycle usually being one day), which is regarded in terms of the average amount of ageing that occurs during the cycle. The cyclic loading may either be a normal loading, or a long-time emergency loading.

Development means activities to either create a new asset or to materially increase the service performance of an existing asset.

Distribution Transformer means a transformer which steps distribution voltage, generally 11 kV but in some cases 6.6 kV or 22 kV, with ON cooling and without on-load tap changing.

Economic Life means the period from the acquisition of the asset to the time when the asset, while physically able to provide a service, ceases to be the lowest cost alternative to satisfy a particular level of service.

Failure means the event in which a component does not operate as intended or stops operating as intended. An example of the first kind is a circuit breaker that fails to trip, an example of the second kind is a transformer that is tripped by its Buchholz relay.

FIDI (Feeder Interruption Duration Index) means the total duration of interruptions of supply that a consumer experiences in the period under consideration on a distribution feeder. FAIDI is measured in minutes/customer/year.

Firm Capacity means the capacity of the lowest rated second incoming supply to a substation (in the case of a single supply substation it is zero).

Forced Outage means the unplanned removal of a primary component from the system due to one or more failures in the system. A failure does not have to lead to an outage, for instance the failure of a transformer cooler will just de-rate the transformer.

GXP means the Transmission grid exit point from where Powerco takes supply.

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ICP means installation control point, which is the point of connection of a consumer onto the Powerco network.

Interruption means an unplanned zero-voltage situation of one minute or longer affecting three or more ICPs due to an outage in the system.

Maintenance means activities necessary for retaining an asset as near as practical to its original condition, but excluding renewal of the asset. Replacement of sub-components of an asset can be considered maintenance in this context.

Medium Power Transformer as defined in IEC 354 means a transformer with separate windings having a rating not exceeding 100MVA for three-phase transformers as a medium power transformer. Powerco’s largest transformers are 24 MVA.

Long-time Emergency Cyclic Loading as defined in IEC 354 means load resulting from the prolonged outage of some system elements that will not be reconnected before a steady state temperature rise is reached in the transformer as the long-time emergency cyclic loading. This is not a normal operating condition and its occurrence is expected to be rare, but it may persist for weeks or even months and can lead to considerable ageing. However, it should not be the cause of breakdown due to thermal distribution or reduction of dielectric strength.

Outage means the removal of a primary component from the system.

Redundant Unit means a component whose outage will never lead to an interruption in the base state, but for which at least one contingency state exists for which its outage will lead to an interruption.

Refurbishment means activities to rebuild or replace parts or components of an asset, to restore it to a required functional condition. Generally involves repairing the asset to deliver its original service performance for an extended time. In this plan, refurbishment is a maintenance activity.

Reliability Assessment means determining the optimum solution to any required system reinforcement by quantifying the benefits of proposed works and/or enabling a quantitative comparison of alternative system configurations.

Renewal means activities to replace an existing asset with one of equivalent service performance capability.

Repair means the restoration of the functionality of a component, either by replacing the component or by repairing it.

Repair Time means the time delay between a forced outage and restoration of the faulty unit only.

Replacement means the complete replacement of an asset that has reached the end of its life, so as to provide a similar level of service, or agreed alternative level of service.

SAIDI (System Average Interruption Duration Index) means the average total of interruptions of supply that a consumer experiences in the period under consideration. The classes of SAIDI are: class A is Transpower planned outages; class B is Powerco planned outages; class C is Powerco unplanned outages; and class D is Transpower unplanned outages.

SAIFI (System Average Interruption Frequency Index) means the average number of interruptions of supply that a consumer experiences in the period under consideration. The classes of SAIFI are: class A is Transpower planned outages; class B is Powerco planned outages; class C is Powerco unplanned outages; and class D is Transpower unplanned outages.

Scheduled Outage means the planned temporary removal of a primary component from the system.

Security means the ability of the system to meet the service performance demanded of it during and after a transient or dynamic disturbance of the system or an outage to a component of the system.

Service Performance means the level of service delivered in respect of quality, capacity and reliability in terms of the provision of line function services.

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Service Potential means the total future service performance of an asset. It is normally determined by reference to the service performance and economic life of an asset.

Short-time Emergency Loading as defined in IEC 354 means unusually heavy loading due to the occurrence of one or more unlikely events which seriously disturb normal system loading, causing the conductor hot spots to reach dangerous levels and, possibly, a temporary reduction in the dielectric strength. However, acceptance of this condition for a short time may be preferable to other alternatives. This type of loading is expected to occur rarely and it must be rapidly reduced or the transformer disconnected within a short time in order to avoid its failure. The permissible duration of this load is shorter than the thermal time constant of the transformer and depends on the operating temperature before the increase in the loading; typically, it would be less than half an hour.

Switching Time means the time delay between a forced outage and restoration of power by switching of a single switch within the power system.

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3. Background and Objectives

3.1 About this Plan Powerco’s electricity system assets range in age from new to over 50 years. The management of these assets is critical to Powerco providing an efficient and effective service to its consumers.

The plan is intended to demonstrate responsible management of the electricity system assets by Powerco on behalf of its consumers and shareholders.

This plan incorporates revisions to performance measurements and lifecycle maintenance strategies. Since the release of the previous plan the long term development plan has been completed, and summary information from it is included in this document. Preparation of the medium term development plan is in progress but has not been completed in time for inclusion in this document.

3.2 Period Covered by the Plan The Asset Management Plan covers a period of ten years from the financial year beginning on 1 April 2002 (the 2003 financial year) until the year ending 31 March 2012. The main focus is the first three to five years. Beyond this general forecasts are made which are reviewed annually.

3.3 Interaction with Corporate Planning and Objectives The Asset Management Plan is a key input into the corporate planning process. Conversely, key corporate objectives influence the direction of the asset management process. The interface between corporate planning and asset management planning occurs at executive team and Board level. The executive team and the Board review both the AMP and the company business plan. The General Manager Network Assets or other members of the executive team address any issues or conflicts between the two plans.

3.4 Future Review of this Plan This plan will be reviewed annually in line with other Powerco business plans. The development strategies will be reviewed annually to ensure that they keep pace with changing load patterns. The maintenance strategies will be reviewed as technology and techniques develop. Changes in these strategies will be incorporated into the plan during the annual review.

3.5 Asset Management Overview and Key Drivers

3.5.1 Purpose of Asset Management The primary purpose of the asset management process at Powerco is to deliver the required level of service in an economically efficient manner that meets the needs of the stakeholders. A balancing of the key drivers is required to achieve this purpose.

3.5.2 Asset Management Performance Drivers A summary of the key asset management drivers is given below:

Service performance is the delivery of “electricity line function” service. The key elements of service in this context are: · Reliability of supply: The factors that drive reliability are explained in more detail in section 5. · Capacity of supply: This is described as the ability of the network to supply the load required. · Quality of the supply: This is described in terms of voltage level, waveform quality and momentary fluctuations.

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Economic efficiency: The delivery of the service through the best use of capital and other resources, considering the opportunity cost of performing the activity. The key factors that drive economic efficiency are: · Asset investment: The level of capital investment in the assets to delivery the service. The key performance driver in the asset management context is the level of asset utilisation. · Cost: In this context the overhead, operating and maintenance costs associated with the assets.

Safety, environmental responsibility and risk management are important drivers to maintain long term value (to shareholders) and integrity of the network.

Productivity and commercial efficiency: The delivery of the “asset management” service in a productive/efficient and commercially prudent manner. This is an inherent driver that has been separated out for clarify and focus.

To deliver on the primary purpose of asset management, the asset manager needs to balance service, cost and asset investment to best meet the stakeholder needs.

3.5.3 Stakeholder Interests in the Asset Management Process The diagram below illustrates the relationship between the main stakeholders and drivers and the asset management process. Each of the key stakeholder groups is discussed below.

Figure 3: Asset Management Process

3.5.3.1 Powerco’s Consumers In the context of this plan the consumers are the people, organisations and businesses who rely on the delivery of electricity from Powerco. They wish to receive a safe, reliable, high quality supply of electricity at the lowest possible price.

Except for new connection work, the energy retailers manage the interests of the consumers. Service levels, pricing and other consumer issues are addressed in the retailer Use of System Agreements agreed between retailers and Powerco.

For new connection work the consumer deals with an approved contractor and any planning related issues are addressed between the contractor or consumer and Powerco.

3.5.3.2 Powerco Shareholders Powerco’s shareholders wish to ensure, as owners of the assets, that their share value and dividend yield are commensurate with the risk of their investment. This is achieved by ensuring that the development, operation and maintenance of the network are optimised to enable an appropriate return within statutory limits.

3.5.3.3 Government The key government regulatory agencies that have jurisdiction over Powerco’s activities include the Commerce Commission and the Ministry of Economic Development. The key driver from the Government is outlined in the government policy statement (the overall objective has been repeated below).

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The Government's overall objective is to ensure that electricity is delivered in an efficient, fair, reliable and environmentally sustainable manner to all classes of consumer. Industry arrangements should promote the satisfaction of consumers' electricity requirements in a manner which is least-cost to the economy as a whole and is consistent with sustainable development.

3.5.3.4 Other Stakeholders Other stakeholders with an interest in Powerco’s asset management include employees and contractors who work on the system, the public through whose land the distribution system is built, the electricity industry (MARIA, MACQS and the EGB) and any local and central government authorities that have jurisdiction over Powerco’s activities. The input these parties have into the AMP is addressed at various stages of the planning process.

3.6 Responsibilities and Accountabilities for Asset Management

3.6.1 Powerco Company Structure Powerco Limited has been organised along business process lines and operating responsibilities allocated to defined business units. The company structure for Powerco is shown in the following diagram:

POWERCO BOARD

POWERCO

Regulated Business Ownership Services Income § Implement Strategies and Plans § Deliver Corporate Finance and Treasury Services supplied to: § Deliver Business Growth § Manage Regulatory Environment Regulated § Deliver Human Resources Support Electricity § Deliver Commmunication/Marketing Services Retailers § Manage Customers & Suppliers

Regulated Gas Key Contracted Customers Asset Management Network Management Network Services § Manage Asset Strategy § Deliver Asset Planning § Deliver Network Performance § Design & Construct Network § Manage Contracts § Maintain Network Customers § Manage Asset Information § Provide Network Access § Manage Load Optimisation (direct and Unregulated § Restore Network through Income Retailers)

Unregulated Other Business Shared Services Contractors § Deliver Finance Support § Deliver Payroll Support § Deliver Information Systems & Telecoms Support § Deliver Supply Chain Services § Deliver Business Advisory Services

Suppliers

Figure 4: Powerco Company Structure

3.6.2 Asset Management Responsibilities at Powerco The Asset Management Group role in Powerco is as the custodian for Powerco’s utility assets. It provides asset management services under contract with the Business Owner. Asset Management is responsible for ensuring that the utility assets are developed, renewed, maintained, operated and used in a long-term sustainable basis to meet the needs of all stakeholders. Monitoring performance, making investment decisions, managing network information, establishing standards, managing work on the network and risk management are included in this work. The Asset Management group is the responsibility of the General Manager Network Assets.

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Within the Asset Management Group there are four teams, which address electricity network planning, gas network planning, contract management, and network information.

Day to day operation of the network is carried out by the Network Management Group, to Asset Management Group requirements.

External consultants are used by the Asset Management Group Planning Engineers and the Contract Managers for expert advice on detail design issues, performing detailed studies and peer review.

Construction and maintenance work is carried out by the Network Services Group or by Contractors.

Powerco is a member of the New Zealand Strategic Technology Program (NZSTP). This program allows Powerco to direct and access research and development into electricity supply issues affecting Powerco or its consumers.

An overview of the Asset Management processes at Powerco is given in the diagram below:

Asset Management Process Overview

Market & Competitor & Governance and Management Industry Best-Practice Information Asset Group Plan Business Management (Strategic Direction) Legislation and Regulatory Business Improvement To all processes Government Planning Review & Industry Requirements Policy Governance Disclosure

Manage Asset Strategy Deliver Asset Planning Manage Contracts

Customer, Investment & Risk Asset Strategy 2 Planning Cycle Asset 2 Set Requirements Asset Owner Asset Strategy 1 Outsourcing Performance & Investment Needs, Asset Strategy Review Asset Develop Solutions To Asset Planning Cycle Asset 1 Policy Risk & Investment Policy Management Meet Performance Valuation Asset ReviewPerformance Asset DevelopRequirements Solutions To And Valuation ManagementDrivers Meet PerformanceGrowth Performance Requirements And Contract Asset Management Plan Drivers Growth Annual Works Plan Design, Construction Preparation Investment & Materials Standards And Planning Asset Operating Standards Investment Tendering/ Review Delivery Planning Negotiation Line Asset Valuation Of Performance Pricing & Expenditure Forecast From Existing Compile Asset Assets Management Plan, Construction Contract Demand Standards And Progress Forecasting Operating Policy From Management Demand Solutions Forecasting Retailers & Customer Load Information Customers Customer Complaints

Customer Network

Initiated Work Improvement Designs Registry ICP Information Process Interface Process Operatonal Information "As-Built", Maintenance and Contracts & Project Conceptual

Billing ICP Information Information on Assets and their Contractor Process History and Performance Undertakes (to all processes) Required Work

Note: Manage Asset Information 1. The interface between the Contractor and the Network Network Asset Information Management Centre is not shown. Information Information Asset Information Asset Information "As-Built", Maintenance and Operatonal Information 2. The Network Management Centre Auditing & Systems Maintenance Reporting operates under contract with Asset Verification Management

Version 7 10 May 2002 Figure 5: Asset Management Process Review

3.6.3 Asset Management Reporting The General Manager Network Assets provides monthly reporting against the AMP to the Chief Executive and Board of Directors. Detailed quarterly reporting is provided for the performance of each network region and the productivity of the Contractors working on the network. The asset management activities are reported against a balanced scorecard of performance measures. The scorecard reflects financial, consumer, process and improvement/learning areas of the business.

Major requests for capital are approved by the Board to ensure that appropriate economic viability investigation has been undertaken and that the proposed project considers the needs of company, shareholders and consumers.

An audit of actual asset renewal expenditure against the required asset renewal expenditure will be performed annually. The purpose of this audit is to ensure that renewal work is not being deferred or prematurely advanced to the detriment of the service level or stakeholders.

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3.7 Asset Management Information Systems Asset management information systems have been developed at Powerco to support the asset management processes. The information system consists of the following main systems: · The Geonet Geographical Information System (GIS) · The Mainsaver Maintenance and Work Management System (CMMS and WMS) · The Electrical Network System (ENS) · SCADA data · Financial System · Ancillary databases · Manual Records

The Network Information System Strategic Plan (NISSP) contains the strategic direction and proposed projects for asset management information systems. A summary of each system is provided below.

3.7.1 Geographical Information System (GIS) Powerco operates a GIS for the management of spatial asset information. The software product used is Geonet. The system is in its final stages of full implementation, and contains various levels of detail for the different areas that make up the Powerco network.

The GIS contains spatial and attribute information on the following assets and types: · Overhead lines (33, 22,11,6.6, 0.4kV) · Underground cables (33, 22,11,6.6, 0.4kV) · Distribution transformers · Switches and fusing (33kV and 22,11,6.6kV) · Associated distribution equipment (pillar boxes, stay wires, etc)

Phase 2 of the software development and data capture or conversion is complete, and all lines and cables within the electricity service area are in the system. The basic software development is complete, providing basic functionality to most users. This functionality is provided by full Geonet Licences for full users, Citrix based viewers for mid range users, and intranet viewers for other users.

The GIS or ENS are the master systems for current distribution system assets. The maintenance, work management and financial systems operate as slave systems off the GIS or ENS asset information.

The GIS allows accurate calculation of line lengths and asset types for calculating the network optimised depreciated replacement cost (ODRC). The asset spatial information is a key input into maintenance scheduling where geographical factors are considered.

3.7.2 Zone Substation Asset Register Powerco has created a zone substation asset register for the financial management and ODRC preparation for all assets contained within the zone substations. This system is presently the master record set for zone substation assets.

3.7.3 Maintenance and Works Management System Powerco operates a maintenance and works management system (WMS) to schedule maintenance activities, manage defect repairs and planned work on the network. The software products used are Mainsaver, which is an off-the-shelf maintenance management system, and WMS, which is a Powerco specific works management system which acts also as an integrator between the various databases.

A major project is scheduled for completion by the end of July 2002 to enhance the data in Mainsaver, and enhance the integration between Mainsaver and the GIS and Olympick Job Costing and Inventory systems.

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The CMMS and WMS systems will be used extensively to manage the condition monitoring, routine maintenance and replacement of the electricity network assets.

3.7.4 Ancillary Databases & Financial System Powerco operates ancillary electronic databases for control and issuing of installation connection point (ICP) information to retailers, and to control manual drawings and documents. Where necessary these databases are reconciled to the GIS either monthly or quarterly.

Powerco maintains a comprehensive fault management database that is integrated with mobile data terminals in the field service vehicles. The fault database contains information on all faults and first response jobs that are undertaken on the network.

Powerco also maintains a comprehensive protection database for the management of settings in numerical and electromechanical protection relays.

Powerco uses the Olympick financial system for the management of expense and capital accounts, accounts payable and receivable.

3.7.5 Manual Record Systems In addition to the electronic systems, several manual recording systems are maintained, these include: · zone substation drawings · standard construction drawings · equipment operating and service manuals · manual maintenance records · network operating information (system capacity information and operating policy) · policy documentation · HV and LV schematic drawings

3.7.6 Drawing Management System The drawing management system is based on AutoManager Workflow and works in conjunction with AutoCad drawing software to make up the complete drawing management system. It is a database of all engineering drawings including substation schematics, structure drawings, wiring diagrams, regulator stations and metering stations. In addition there is a separate environment that contains legal documents.

AM Workflow has the ability to attach an electronic copy of the drawing/document to the index card. It also allows the user to “red line”, control revisions and print. All drawings are indexed into the AM Workflow system.

3.7.7 Information Integrity and Improvement Actions Extensive effort is made to ensure the integrity of the asset information. This includes auditing of as-built information against the physical work, checking of GIS additions against the as-built information and formal auditing.

A number of significant data and system rationalisation projects have commenced and will continue into 2003. These projects are details in the NISSP and have been summarised below: · The centralisation of asset data into the GIS. A key feature of the project is to make the GIS system the master for all asset records. The project involves the transfer of information from ENS, the zone substation database and other ancillary databases. Other systems such as Mainsaver will contain a synchronised copy of essential asset information from GIS systems. · The recording in GIS of the expected renewal date for assets planned to be replaced in the near term. This information is being captured but is presently analysed in ancillary databases. · The enhancement of functionality in the GIS and viewer software. · The integration of Mainsaver with the financial job costing system. · “As-builting” and redrawing critical zone substation drawings.

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4. Details of the Assets

4.1 Infrastructure Assets This plan covers the infrastructure assets owned by Powerco Limited. These are defined as all network system fixed assets: · subtransmission system · zone substations, including buildings. · high voltage distribution systems · distribution substations, transformers and switchgear · low voltage distribution systems including consumer service connections · SCADA and communication systems

The infrastructure assets do not include: · land and buildings, except zone substation buildings. · consumer revenue meters and load control relays, which are owned by energy retailers, although this is being reviewed. · non-system fixed assets such as motor vehicles, furniture and office equipment, plant, tools, etc. · net financial assets · stores and spares

4.2 Subtransmission System Configuration Powerco has an extensive urban and rural network serving Taranaki, Wanganui, Rangitikei, Manawatu, Tararua and Wairarapa.

The network comprises a 33 kV subtransmission system supplying 63 zone substations. These are mostly 33/11 kV, but a few are 33/6.6 kV, and some supply 22 kV from 11/22 kV transformers. A radial feeder network runs from the zone substations throughout the service area. Powerco receives power from Transpower at 17 Transpower grid exit points (GXPs), at 33 kV and/or 11 kV, from Trustpower at three hydro power stations and one wind farm, from NZ Energy at two hydro power stations, and from Genesis Energy at one wind farm.

The Taranaki region has three areas, based on the electricity supply authorities that used to operate them. These are New Plymouth, Taranaki and Egmont.

The New Plymouth subtransmission network consists of two 33 kV cables supplying City Substation from Carrington GXP, two 33 kV lines from Carrington GXP and one 33 kV line from Huirangi GXP supplying Bell Block Substation, two 33 kV cables from New Plymouth Power Station (NPPS) GXP to Moturoa GXP, but owned by Powerco, and two 33 kV lines from Huirangi GXP to Mamaku Rd Substation.

The Taranaki subtransmission network is an interconnected network supplying eleven zone substations from Huirangi GXP and Stratford GXP.

The Egmont subtransmission network consists of Cambria Substation supplied via two oil filled 33 kV cables, and four other zone substations supplied via an interconnected 33 kV line network from Hawera GXP. It also supplies three zone substations from Opunake GXP via an interconnected 33 kV line network.

The Wanganui network consists of three areas, Wanganui, Marton and Taihape.

The Wanganui area is supplied from two Transpower GXPs at opposite sides of the city, Wanganui GXP and Brunswick GXP. A 33 kV line runs between these, passing through zone substations at Peat St, Castlecliff, Beach Rd and Taupo Quay on the way. Hatricks Wharf substation is connected by 33 kV line to Wanganui GXP and by 33 kV cable and line to Peat St. A radial line connects Peat St to Kai Iwi zone substation, and another connects Brunswick GXP to Roberts Ave zone substation. A radial line connects

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Wanganui GXP to Wanganui East zone substation, and two short radial lines connect Wanganui GXP to the adjacent Blink Bonnie zone substation.

The Marton area is supplied from Marton GXP. One line connects Marton GXP to Bulls zone substation. Another line connects Marton GXP to Arahina and Rata zone substations, and a short cable connects Marton GXP to the adjacent Pukepapa substation.

The Taihape area is supplied from Mataroa GXP. It is connected to Taihape zone substation by three lines, two of which are in parallel, to form two circuits, and it is connected to Waiouru zone substation by a single line.

The Manawatu region has three areas, based on the electricity supply authorities that used to operate them. These are Manawatu, Palmerston North and Tararua.

The Manawatu rural subtransmission network consists of an open 33kV ring feeding four substations around the periphery of Palmerston North and 33kV radial feeders to Sanson and Kimbolton via Feilding. The Feilding substation supplies all Feilding load. The 33kV circuits are predominately overhead construction on concrete poles.

Outlying suburbs and rural areas close to Palmerston North are supplied from the Kelvin Grove, Milson, Kairanga and Turitea substations. These substations are located on the periphery of Palmerston North. All of these substations are supplied by two 33kV circuits from either Linton GXP or Bunnythorpe GXP.

Turitea Substation incorporates neutral earthing resistors in order to limit fault levels.

The Palmerston North urban subtransmission network comprises three 33/11kV zone substations. Keith Street substation, at the north-eastern periphery of the urban area of Palmerston North, is supplied by two 33 kV circuits from Bunnythorpe and an interconnection to Kelvin Grove substation. Pascal Street substation, at the western end of the City, takes supply via 33 kV circuits from Bunnythorpe and Linton. Two circuits from Keith Street and a single circuit from Pascal Street supply Main Street substation. All 33kV subtransmission circuits are underground in the city area. 33kV circuits outside this area are of overhead construction on concrete poles.

The Tararua network, formerly operated by the Tararua Electric Power Board, consists of four zone substations supplied from Mangamaire GXP. It has two 33kV rings, one feeding Mangamutu substation, the other feeding three zone substations in the area south to Eketahuna and east to Pongaroa.

The Wairarapa subtransmission network is supplied from Masterton GXP and Greytown GXP.

Masterton GXP supplies Akura and Te Ore Ore zone substations in a ring. A single line eastwards from Te Ore Ore supplies Awatoitoi and Tinui zone substations. Masterton GXP also supplies Norfolk and Chapel zone substations on a ring which is part line and part cable. It also supplies Clareville substation via two lines and Gladstone substation via a single line.

Greytown GXP supplies an interconnected line network which supplies Featherston and Martinborough zone substations by two lines each, and Kempton, Hau Nui and Tuitarata zone substations by one line each.

The majority of the rural networks are of overhead construction, on wood or concrete poles. Short lengths of 33kV cable are used at some zone substations. The load density in the service areas is relatively low and thus conductor sizes are generally light.

4.3 Zone Substation Configuration Powerco has 63 zone substations, the majority being 33/11 kV, but some in Taranaki are 33/6.6 kV. There is some 22 kV distribution in the Rangitikei area, which is supplied via 11/22 kV transformers.

Zone substation transformer capacities vary from 1.25 MVA to 24MVA.

The substations supplying urban/industrial loads typically have two transformer banks, two incoming 33kV feeders and anywhere between 4 and 15 outgoing distribution voltage feeders, except in the Wanganui area where single transformer substations are generally used.

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For rural substations only one transformer bank is normally provided, and there are typically only three distribution voltage feeders.

Details of security of supply classes are given in Section 5 of this document.

4.4 Distribution Network Configuration

4.4.1 Central Business District Network Configuration The networks in the Palmerston North, New Plymouth, Wanganui and Masterton Central Business Districts (CBDs) consist of highly interconnected 11 kV radial feeders. Switching points are provided at most 11kV/400V transformer locations. There is a high level of interconnection between adjacent 11kV feeders. The reticulation in the CBDs is 100% underground with cable sizes ranging from 95mm2 to 300 mm2 aluminium or copper. 11kV switch automation is being progressively introduced in key locations, and provision for future automation is being provided at less critical locations. This configuration allows quick restoration of supply in fault situations.

The 400V system consists of radial circuits with a high degree of interconnection. The interconnection between distribution substations is made at junction boxes located along the 400V circuits. The cable sizes typically are large (up to 0.5 sq inch copper). The 400V system is 100% underground in the CBDs. Significant load can be transferred across the 400V system.

The business district configurations of Waitara, Inglewood, Stratford, Hawera, Opunake, Marton, Taihape, Feilding, Pahiatua, Carterton, Greytown and Featherston fall under the “urban network configuration” definition. In these towns the business district is largely or completely underground.

4.4.2 Urban Network Configuration Both 11kV and 400V urban distribution systems are interconnected radial systems. The level of interconnection is moderate, commensurate with the reliability requirements. In some urban areas, the distance and/or load between switching points is outside Powerco’s planning criteria requirements. Load transfer between distribution substations is possible through the 400V system.

4.4.3 Industrial And Commercial Consumer Network Configuration The network configuration for large industrial consumers is commensurate with the nature of the consumer’s operation and capacity demand. Typically, for consumers with a demand above 3MVA, dual 11kV feeders are available, allowing for continuation of supply in the event of maintenance or equipment failure. Automation or remote control of 11kV switching is provided for some major consumers. The cable and conductor sizes reflect the load size. Conductor sizes up to 300mm2 copper are used.

Due to the higher load current requirements there is limited load transfer capacity through the 400V system. Typically radial 400V feeders from the transformer to the consumer are provided. In some industrial subdivisions 400V interconnection between feeders is provided using either 240mm2 or 185mm2 aluminium cable.

4.4.4 Rural Network Configuration The rural network consists of 11kV isolators installed every 1-2kms. This enables flexibility of switching, but does present a maintenance and reliability liability. A number of 11kV spur lines are fused with expulsive fuses. Some interconnection between feeders is present to allow backfeeding in maintenance and fault situations. The feeder construction is overhead on wooden or concrete poles.

Use is made of line reclosers and sectionalisers in the rural areas. Typically reclosers are placed at the transition between urban and rural loads and between rural and remote rural loads, and sectionalisers are used on some spur lines.

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4.4.5 Remote Rural Network Configuration Remote rural feeders are radial with limited interconnection with adjacent feeders. In some areas, switching along the feeders is provided by 11kV isolators and 11kV expulsive fuses. This provides good discrimination and sectionalising under fault conditions. The feeders are all overhead construction on wooden and concrete poles.

Due to the scattered nature of the population there are no significant 400V networks. Typically, the 400V system extends 100-200m under the main distribution voltage lines from the distribution transformer to supply adjacent housing.

4.5 Justification for Assets

4.5.1 General Assets are required to deliver electricity from the generating source to the consumer. The required assets range from subtransmission assets down to low voltage reticulation along a residential street. Powerco uses various voltages to optimise the cost of construction versus the cost of losses for different distribution distances.

4.5.2 Subtransmission Assets Subtransmission assets carry electricity at 33kV from the Transpower or generating company connection points to the zone substations, although this does not preclude using other standard voltages in the future. To provide a reliable supply of electricity to the zone substations redundancy is built into the system by way of duplicated or interconnected lines in many places.

Given the large amount of supply lost if a zone substation is not operating, a highly reliable subtransmission network is required.

4.5.3 Zone Substation Assets Zone substations convert the electricity voltage from 33kV to 22 kV, 11kV or 6.6 kV. Zone substations are required because 33kV lines are not an economically viable means of distributing electricity to individual consumers or groups of consumers, with the exception of large consumers with loads above about 8 MVA.

Given the large amount of electricity being supplied through a zone substation, equipment redundancy is often provided. Having duplicate assets at a zone substation allows maintenance to be performed without the need for a supply interruption and allows supply to be maintained in the event of an equipment failure.

4.5.4 High Voltage Distribution Assets Electricity is distributed to consumers or groups of consumers using 22 kV, 11kV or 6.6 kV lines. These lines (or feeders) provide an economical means for distribution of electricity to groups of consumers. As 400/230 volt distribution is limited to around 200-400 metres, distribution feeders constitute the highest percentage of total network assets.

Interconnection is provided between adjacent feeders to allow supply to be restored in the event of a fault, or to facilitate maintenance without significant supply interruptions. Switches are also provided along the feeder to aid fault finding, to reduce outage areas, and to facilitate maintenance.

4.5.5 Distribution Substation Assets Distribution substations convert electricity from the distribution voltage to 230/400V that can be utilised by consumers. Distribution substations are located as close to groups of consumers as practicable, as electricity cannot typically be distributed more than about 400m by 230/400V lines without excessive voltage drop.

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4.5.6 400V Distribution Assets 400V assets consist of 400V lines, cables, link boxes and pillar-boxes. Consumers typically connect to Powerco’s network at pillar-boxes located on the boundary of their properties or by an overhead service line to a pole mounted fuse. Ownership of service lines varies depending on the policy in place at the time of installation, but they are generally owned by consumers.

4.5.7 SCADA and Communication Assets Other network assets are Powerco’s SCADA, radio microwave and cable communication systems. These systems are used to monitor the status of the network and to enable some assets to be operated remotely.

4.6 The Assets By Category, Age and Condition

4.6.1 Assets Categories For the purposes of reporting in this plan the major categories of assets have been defined as: · Distribution transformers · Underground cables · Overhead lines · Zone substation assets · Subtransmission and distribution switchgear

The replacement costs by asset category is shown in the figure below. The asset replacement cost used have been based on the MoED ODV handbook standard replacement costs.

350,000

300,000

250,000

200,000

150,000

100,000 Replacement Costs ($000)

50,000

- Distribution Transformer Underground Cable Overhead Line Zone Substation Equipment HV Switchgear Asset Category

Figure 6: Replacement Cost by Asset Category

4.6.2 The Assets By Age The average age of the distribution network is around 23 years. Table 4 below summaries the average standard life and average age for different asset categories.

Table 4: Average Age of Assets Asset Category Average Design Average Age at Life 31/03/02 Distribution Transformer 45 21 Underground Cable 65 25 Overhead Line 56 27 Zone Substation Assets 43 22 Subtransmission & Distribution Switchgear 37 24

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Asset replacement cost versus age graphs are presented below and indicate the overall age of the assets. It should be noted that equipment with different life spans are included in these graphs. Graphs showing replacement cost against year of replacement are included in section 6.11.

$40,000 Substations $35,000 Switches Transformers

$30,000 Cable Overhead Line

$25,000

$20,000

$15,000

$10,000 Replacement Cost ($000)

$5,000

$0 1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 49 51 53 55 57 59 61 63 65 67 69 71 73 75 77 79 Age (Years) Figure 7: Total Asset Replacement Cost vs Age

$14,000

Overhead Line Replacement Cost $12,000

$10,000

$8,000

$6,000

$4,000 Replacement Cost ($000)

$2,000

$0 1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 49 51 53 55 57 59 61 63 65 67 69 71 Age (Years)

Figure 8: 33/11/0.4kV Overhead Line Replacement Cost vs Age

14000

Cable Replacement Cost

12000

10000

8000

6000

4000 Replacement Cost ($000)

2000

0 1 4 7 10 13 16 19 22 25 28 31 34 37 40 43 46 49 52 55 58 61 64 67 70 Age (Years) Figure 9: 33/11/0.4kV Underground Cable Replacement Cost vs Age

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$4,000 Distribution Transformer Replacement Cost $3,500

$3,000

$2,500

$2,000

$1,500

Replacemnet Cost ($000) $1,000

$500

$0 1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 49 51 53 55 57 59 61 63 65 67 69 71 Age (Years)

Figure 10: 11/0.4kV Distribution Transformer Replacement Cost vs Age

$9,000 HV Switch Replacement Cost $8,000

$7,000

$6,000

$5,000

$4,000

$3,000

Replacement Cost ($000) $2,000

$1,000

$0 1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 49 51 53 55 57 59 61 63 65 67 69 71 Ages (Years) Figure 11: 33/11kV Switchgear Replacement Cost vs Age

$7,000 Substation Equipment Replacement Cost

$6,000

$5,000

$4,000

$3,000

$2,000 Replacement Cost ($000)

$1,000

$0 1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 49 51 53 55 57 59 61 63 65 67 69 Age (Years) Figure 12: Substation Equipment Replacement Cost vs Age

4.6.3 Asset Condition

4.6.3.1 Summary In summary, the condition of all infrastructure assets is maintained to a level commensurate with the nature of the asset, the environmental conditions and the consumers’ reliability requirements.

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The asset condition is monitored through the use of inspection and condition monitoring techniques. An overview of the inspection and condition monitoring techniques is given in section 6.11.

4.6.3.2 Overhead Line Condition The condition monitoring undertaken shows that most lines are in the condition to be expected for their age, although some in harsh coastal areas have deteriorated faster than expected.

4.6.3.3 Underground Cable Condition The 33 kV cables from Carrington GXP to City substation are suspected of having corroding aluminium conductors and screens. Partial discharge tests and sheath tests are programmed.

The 33 kV oil filled cables are more than thirty years old. They may need to be replaced prematurely if the cost of fault repairs becomes uneconomic. Presently this is not the case.

For other 33kV cables no replacement due to age or condition is expected during the period covered by this plan.

Powerco commenced underground construction in the 1950s. Some early 11 kV PILC cables in the New Plymouth area have brittle lead sheaths, prone to cracking. These cannot be moved, and where more than one are laid in a common trench, jointing is difficult. These cables will be replaced or abandoned as Carrington GXP 11 kV bus is replaced or upgraded, expected within five years.

The other cables that may require early replacement are aluminium XLPE cables installed in the late 1960s and 1970s. This was first generation XLPE and was manufactured using water-curing techniques. This, coupled with a lack of knowledge and subsequent poor handling of the cable during installation, has resulted in some cable failures. Otherwise no expenditure is expected for 11kV cable replacement for some time. The early cables were PILC, which has a life expectancy of seventy years or more, provided it is not moved.

Like the 11 kV cable installation, no 400V cables were installed prior to the 1950s. These early cables were also PILC construction with a 70 year plus expected life.

Powerco’s assessment of the older 400V cables during excavation works indicates that the cables are not ageing more than expected. It is not expected that any significant replacement will be required prior to 2010.

Powerco has some single core Aluminium conductor cable with only a single layer of insulation. It is possible that this insulation may breakdown prior to the forecast replacement date. This is being monitored.

4.6.3.4 Distribution Transformer Condition Condition monitoring undertaken shows that most transformers are in the condition to be expected for their age, although some in harsh coastal areas have deteriorated faster than expected.

4.6.3.5 33 kV and 11 kV Switchgear Condition Significant condition monitoring is undertaken on the zone substation assets, and most are in good condition. Two types of switch which have raised safety concerns are programmed for replacement.

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5. Performance Levels

5.1 Introduction This section of the plan outlines the targeted performance levels required from the network. The section deals with the consumer related service requirements and the other service requirements relating to the other business drivers.

The key performance drivers were described briefly in section three. Each aspect of performance has been expanded in the following sections.

5.2 Target Levels of Consumer Service (Service Performance)

5.2.1 Overview The levels of service adopted by Powerco for its asset management plan are based on the internationally recognised measurements, SAIDI, CAIDI, and SAIFI and accepted New Zealand lines companies’ ‘best practice’. These criteria, which are described below, have been adopted as a starting point for asset management planning.

The specific target levels of service chosen are based on a balance of past practice, economic factors, recognised international best practice, and safety considerations. These criteria have been refined over recent years to reflect the direction indicated by government reviews involving all facets of the industry, consumer groupings, and individual submissions, conducted during the recent industry restructuring process. In setting these criteria Powerco believes it achieves an appropriate balance between legislative, regulatory, shareholder requirements and consumer expectations.

5.2.2 Definition of Consumer Service and Service Performance For the purpose of this plan, it is assumed that so far as receiving a supply of electricity is concerned, the consumer’s general needs will be satisfied if Powerco meets its Service Performance targets. Service Performance is defined as:

“Delivery of electricity line function services to meet consumer load requirements within targeted quality limits, and within targeted levels of reliability”.

The three key elements of the service performance definition are expanded in the following points:

5.2.2.1 Reliability The reliability service component is a function of: · Asset design, the most important mechanism being built-in equipment redundancy, referred to as the security level, so that the failure of any one component does not lead to an unrestorable supply outage. Powerco has developed security criteria for the subtransmission and distribution system and these are key inputs into the planning process. The security criteria are discussed in later sections of this plan. · Asset type; that is, the inherent reliability of the asset. · asset condition where this affects the likelihood of failure of a component · operation and maintenance practices minimising the effects of planned equipment outages. Powerco uses all endeavours as a reasonable and prudent network operator to provide continuous service within the limitations of the network design.

5.2.2.2 Capacity The capacity service component needs to be considered in two parts. Firstly, for the purposes of medium to long term system planning, the consumer load requirements are taken as the present load on the network, plus provision for load growth over five years. The load is taken at the system distribution feeder level. Five years is assumed for this purpose as this is the time within which any necessary network

Powerco Information Disclosure Asset Management Plan Electricity Network 2003 – 2012 Section Subject Date of Issue Page 5 Performance Levels 30/06/02 29 additions could be planned, designed and implemented. The network must be capable of meeting the demand up to the time when any necessary reinforcements or additions could be brought into service. The capacity targets are dealt with as a planning criteria for network development planning in later sections of this plan.

Secondly, in the context of the individual consumer connection the ‘consumer load requirement’ is taken as the present consumers’ load. That is, at an individual consumer level (typically measured at point of common coupling on the 400V system) Powerco is targeting to deliver capacity to meet the present individual consumer load requirements. In most parts of the network there is spare capacity available in the 400V system to accommodate individual consumer load qrowth, however, changes to individual consumers load (or the addition of new consumers) is subject to the investment criteria within the Powerco Investment into Consumer Initiated Work Policy.

5.2.2.3 Quality The elements of supply quality are discussed below: · Voltage: The maintenance of the voltage at the consumers’ point of connection within the statutory voltage limits. · Momentary voltage fluctuations: The momentary departure of the voltage outside the statutory limits. · Harmonics: The distortion of the voltage waveform. Maintenance of frequency is not mentioned as it is not presently under the control of Powerco except for the installation of under frequency load shedding relays at zone substations.

5.2.3 Reliability Targets System reliability is maintained in accordance with accepted industry standards. Powerco sets reliability targets at a system and feeder level.

Each distribution feeder is assigned a feeder class that best encompasses the types of consumers connected to the feeder. In some instances the feeder class changes (only from a higher to lower class) along the feeder. This transition typically occurs at a distribution recloser or protection element. The feeder level reliability targets are used as the best “proxy” from individual consumer reliability targets.

Acceptable reliability performance shall be taken to mean performance equal to or better than the performance indices stated in Table 5 below. The table below indicates the average and maximum (worst case) thresholds for feeder class reliability performance.

Table 5: Reliability Performance Targets by Feeder (Consumer) Type Typical Consumer Type Large Commer- Urban Rural Remote Unit Industrial cial Rural Powerco Feeder Class F1 F2 F3 F4 F5 Average number of 5 100 800 500 250 consumers on feeder class SAIFI (average for class) 0.33 0.33 0.5 2 3 interruptions per year CAIDI (average for class) 45 45 45 90 150 minutes per interruption SAIDI (average for class) 15 15 23 180 450 minutes per consumer per year Maximum No. of auto- 16 24 reclose shots per year recloses Maximum No. of Interruption 0.5 1.0 1.5 4 6 interruptions per year Maximum average outage 60 60 120 150 180 minutes per interruption duration Feeder interruption duration 30 60 180 600 1080 minutes per feeder per index (FIDI) year

Note: The reliability performance stated in the table above includes the performance of the system upstream of the feeder.

Extrapolating the average reliability performance targets across the system provides the total system performance target. Table 6 below summarises the calculation.

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Table 6: Derivation of System Average Reliability from Feeder Class Average Reliability Powerco Feeder Class F1 F2 F3 F4 F5 Estimated No. of consumers per class 320 6,395 102,322 31,976 15,988 Annual consumer minutes 4,748 94,967 2,302,240 5,755,601 7,194,501 Total annual consumer minutes 15,352,058 Total consumers 157,000 System SAIDI 98

The system reliability targets have been further disaggregated by outage class for the next four years and this is shown in table 7 below. Class B outages relate to planned outages to the Powerco network and class C outages relate to unplanned outages (faults) on the Powerco network. The performance of the transmission network and generators is excluded from the table below.

Table 7: System Reliability Performance by Class and Year Measure Outage Year Unit Class 2003 2004 2005 2006 SAIDI B 25 25 25 25 minutes per consumer per year C 73 73 73 73 SAIFI B 0.2 0.2 0.2 0.2 interruptions per year C 1.7 1.7 1.7 1.7 CAIDI B 153 153 153 153 minutes per interruption C 42 42 42 42 SAIFI B+C 1.9 1.9 1.9 1.9 interruptions per year SAIDI B+C 98 98 98 98 minutes per consumer per year CAIDI B+C 52 52 52 52 minutes per interruption

The customer service target (SAIDI) proposed for 2003 is slightly lower than that targeted for 2002 as the proposed targets now reflects the improvement forecast due to the Network Management Centre restructure and relocation.

5.2.4 Capacity Targets In the context of the individual consumer connection the capacity target is taken as the present consumers’ load. That is, at an individual consumer level (typically measured at point of common coupling on the 400V system) Powerco is targeting to deliver capacity to meet the present individual consumer load requirements.

Capacity management at a system (high voltage) level is an integral part of the planning process. The load vs capacity targets are a key planning criteria component.

5.2.5 Quality Targets Quality of supply targets are considered in the context of: · Voltage regulation · Momentary voltage fluctuations · Harmonics

Powerco’s voltage regulation targets are in line with statutory requirements, which is the voltage shall be maintained within ±6% at the consumer’s point of connection. Performance outside the target is usually indicated by low voltage complaints from consumers. Corrective measures are put in place as soon as possible after the performance gap is identified.

Presently there are no statutory requirements in respect of transient departures from the statutory voltage limits.

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Increasing use of electronic devices is resulting in a progressive deterioration of waveform quality and it is likely that further measures will need to be introduced and enforced in the area of harmonics over the next decade. Harmonics also affect neutral and transformer ratings.

5.3 Target Levels for Additional Service Performance Elements There are a number of other performance targets that are lead indicators for the consumer service aspects of service performance. These targets provide insight into the underlying performance of the network, which ultimately delivers the various elements of service performance.

Security of supply is also a key lead indicator of service performance and the targets are dealt with under the planning criteria section later in this plan.

5.3.1 Targeted Number of Faults per km of line This measure, along with demographic factors leads to realistically achievable targets. It will also identify reliability improvement options which are worth pursuing. (line segmentation, upgrades, additional feeders etc). Regionally, comparing results will identify where improvements can be made by finding the reasons for poor fault/km results.

Table 8: Targeted Future Average Number of Faults per 100km/year Voltage Average No. of Faults per 100km per year 2003 2004 2005 2006 6.6kV 9.7 9.6 9.6 9.5 11kV 9.4 9.3 9.3 9.2 22kV 9.5 9.4 9.3 9.3 33kV 5.9 5.9 5.8 5.8

5.3.2 Number of Interruptions These targets require a steady improvement in fault performance, and reflect Powerco’s intention to improve SAIFI through improved fault performance.

Table 9: Targeted average number of interruptions Interruption Type Average No of Interruptions 2003 2004 2005 2006 Planned Interruption by Powerco (class B) 650 650 650 650 Unplanned interruptions by Powerco (class C) 964 960 955 950

5.4 Target Performance for Economic Efficiency The economic efficiency driver is arguably the most significant of all asset management driver and consideration and balance between service and economic efficiency (asset investment/utilisation and maintenance and operating costs) needs to be considered in asset management decision making. The section below describes how the economic efficiency driver is integrated into the asset management process.

To determine whether economically efficient decisions have been made and whether an economically efficient network operation exists requires measurement of a number of factors. At Powerco the following measurement is made in respect of economic efficiency: · Asset efficiency · Asset utilisation (physical asset capacity utilisation and load factor) · Cost performance

Performance targets for these measures are presented in the sections below.

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5.4.1 Integration of Economic Efficiency Drivers into Asset Management

5.4.1.1 Asset Replacement Economic Assessment Economic efficiency is an important driver for maintenance and development work. A large proportion of repair work, refurbishment and asset replacements are undertaken only after economic analysis to determine the most cost-effective solution. This frequently involves the choice between a replacement option and continued maintenance.

The decision making process for asset replacement is shown in the figure below:

Figure 13: The Asset Replacement Decision Process

To calculate the Marginal Cost of Continued Ownership the follow items are considered: · risk of failure (annualised risk cost) · asset maintenance and operating costs · asset disposal cost · asset market value.

To calculate the Life-Cycle Cost of Ownership of New Asset the following items are considered: · risk of failure (annualised risk cost) · asset maintenance and operating costs · asset disposal cost (this is typically negligible due to the long time to disposal) · asset purchase cost.

Where there are significant “over-riding” risks such as reliability (i.e imminent failure) safety, environmental impact or capacity, a project economic analysis may not be necessary.

There is an inherent economic viability in the safety, environmental and general planning criteria. That is, the standards set under these areas have already been tested for economic sustainability; therefore repeating the economic testing does not add any value.

5.4.1.2 Planning Criteria Economic Assessment Economic viability testing of the planning criteria is performed when the planning criteria is set or reviewed. The life cycle cost of ownership of a notional network or portion of a network constructed using the planning criteria is determined. This cost-of-ownership is tested against other network scenarios to ensure the most economically viable criteria are selected.

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In setting the planning criteria, the balance between service, economic efficiency (asset investment/utilisation and maintenance and operating costs) and reliability needs to be considered. There are significant “trade-offs” to be made with the level of assets employed to provide security and the resulting reliability performance. That is, in general the greater use of assets (providing greater redundancy and security) provides increase service performance, but increases the price of the service (due to the asset investment return requirements and costs).

5.4.1.3 Maintenance Techniques Economic Assessment When maintenance techniques are reviewed or changed, the effect on the long-term asset ownership cost is considered, rather than the short-term effects on maintenance expenditure. The economic analysis would consist of a comparison of the marginal annualised cost of the maintenance, risk costs and disposal over the remaining life of the asset.

5.4.1.4 Consumer Initiated Developments Economic Assessment When determining investment into consumer initiated network developments such as subdivisions and network extensions for new consumers, the expected financial return is weighed against the life-cycle cost of ownership of the new assets. The Powerco investment into the new work is set at the level that will provide the required commercial return given the projected revenue and costs. The payback period considered in the NPV analysis may be adjusted to account for risk of connected business(es).

5.4.2 Asset Efficiency Performance Targets Asset efficiency is a measure of the level of assets employed to provide the service. To allow benchmarking against other electricity lines companies the common measure of Optimised Depreciated Replacement Cost per Consumer (ODRC/ICP) has been used. The measure of ODRC/ICP accounts for the age of the asset (i.e. the depreciated asset cost is used) and hence there can be some distortion when comparing networks with different average ages.

A more consistent measure of asset efficiency is the measure of Replacement cost per Consumer (RC/ICP) which removes the depreciation factor.

Similar measures are developed per MWh delivered.

Powerco’s asset efficiency targets are presented in the table below:

Table 10: Asset Efficiency Performance Targets KPI Description Unit 2003 2004 2005 Asset Efficiency (ODRC/ICP) $/ICP 2400 2400 2400 Asset Efficiency (RC/ICP) $/ICP 4800 4800 4800 Asset Efficiency (ODRC/MWh) (Note 1) $/MWh 180 180 180 Asset Efficiency (RC/MWh) (Note 2) $/MWh 360 360 360 Capital Efficiency (Note 3) % 100 100 100 Change in asset service potential (Note 4) % >0 >0 >0

Notes: 1. Asset efficiency (ODRC/MWh) is the ratio of network optimised depreciated replacement cost over input network MWh. 2. Asset efficiency (RC/MWh) is the ratio of network replacement cost over input network MWh. 3. Capital efficiency is the annual network Capital Expenditure over the change in ODRC as a percentage It will only be calculated when both start and end ODRC values are known. It excludes the reduction due to depreciation and any gain due to asset revaluation during the period. 4. Change in Asset Service Potential is the change in ODRC from year start to year end. It will only be calculated when both start and end ODRC values are known. It includes the reduction due to depreciation but excludes any gain due to asset revaluation during the period.

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5.4.3 Asset Utilisation Performance Targets Asset utilisation is the measurement of the physical utilisation of the assets employed. The utilisation measurements used focus on the utilisation of capacity of the assets. The following utilisation targets, based on international data, are used:

Table 11: Asset Utilisation Performance Targets KPI Description 2003 2004 2005 Zone Substation Transformer 58% 60% >63% Distribution Transformer by supply MD 30% 31% >32% Distribution Transformer by disaggregated feeder MD 38% 42% >45% Distribution Feeder 40% 40% >42% Load Factor 60% 60% 60%

Notes: 1. Zone Substation Transformer utilisation is the substation maximum demand over total substation ONAN rating. 2. Distribution transformer utilisation is calculated for both aggregated and disagregated demand. Aggregated: Network kW MD over distribution transformer capacity. Disaggregated: Sum of disaggregated feeder MDs over distribution transformer capacity. 3. Distribution Feeder utilisation is the disaggregated feeder maximum demand over the total distribution feeder winter 6 pm capacity

5.4.4 Direct Cost Performance Targets For the efficient operation of an electricity network company the direct costs need to be measured. In this plan the performance of direct costs is considered. The total organisation cost have not been considered in the context of this plan as the corporate costs are not under the control of the asset management process. The direct costs include: · Network asset management · Network operating and maintenance · Network control function

The targeted performance for direct cost per km of line is given in the table below:

Table 12: Direct Cost Performance Targets KPI Description 2003 2004 2005 Direct Cost per km of line ($/km) 1346 1336 1338

The Direct Cost per km target for 2003 and beyond are higher than the previously targeted performance due to the direct costs now reflecting market costs for the entire asset management service provision. Previous targets did not reflect the full asset management service costs that would apply in an asset owner – asset manager model. As a consequence, indirect costs will reduce, but this is not a topic for analysis in this plan.

5.5 Target Performance for Safety Electrical plant and equipment are capable of giving rise to danger and measures must be taken to ensure, as far as practicable, the safety of employees and the public.

For the safety of staff and the public, the network must be maintained in a way that meets statutory requirements, follows good engineering practice, and is considered safe in accordance with recognised industry standards.

Safety is determined by a combination of: · asset design · maintaining the assets in a safe condition · safe operating and work practices.

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The statutory safety drivers are: · The Electricity Regulations. These contain the general framework for Powerco’s safety related asset management. The Regulations require existing assets to be maintained in good order and repair to protect from danger. · The Safety Rules – Electrical Industry (SR-EI). This contains the framework for Powerco’s safety related network operation. Powerco has implemented its network operating procedures to comply with the requirements of SR-EI. · The Building Act 1991. This puts in place a building maintenance regime which is aimed at ensuring the existence of essential safeguards for the users of buildings · The Health and Safety in Employment Act 1992. This is a key item of safety legislation. While not overriding safety requirements found in other electrical Acts and Regulations, this Act requires all hazards associated with assets to be identified, assessed, and controlled if found to be significant. This is achieved by duties set on all parties associated with design, construction, maintenance and operation of assets.

Powerco has adopted the practice of working as a reasonable and prudent operator as a guide to safe asset management practices. Its health and safety policy and procedures are set out in documents in the Powerco Quality Management System (QMS).

Powerco’s targeted health & safety performance is given in table 13 below:

Table 13: Safety Performance Targets KPI Description 2003 2004 2005 Asset Management personnel – Number of lost time injuries (LTI’s) 0 0 0 Contractor – Number of lost time injuries (LTI’s) 0 0 0 Public related injuries relating to the electricity network 0 0 0

5.6 Target Performance for Environmental Responsibility Powerco’s policy is to act as a good corporate citizen, in an environmentally responsible manner, and in accordance with legislation. Environmental assessments for Powerco development proposals will continue to be prepared by independent consultants for compliance with the Resource Management Act 1991.

Powerco’s targeted environmental management performance is given in table 14 below:

Table 14: Environmental Management Performance Targets KPI Description 2003 2004 2005 Environmental incidents 0 0 0

5.7 Risk Management The risk management strategy and techniques are explained in a later section of this plan. In summary, risk management is implemented to reduce the likelihood of the targeted performance not being met and to reduce the consequences (to the company and its stakeholders) should this performance not be achieved.

Measurement of the risk management activities is achieved through the monitoring of the key performance indicators and verification that the risks are being considering in the decision making processes.

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6. Network Development and Lifecycle Asset Management Plan

6.1 Introduction This section of the plan describes the aspects of network development, analysis, maintenance management, reliability assessment and associated lifecycle management processes for the network asset.

The planning criteria outlined in the following section have been included to provide background to the considerations made when preparing the long-term development plan.

6.2 Planning Criteria – Long Term Subtransmission Planning The long-term development plan deals with the subtransmission system and zone substations. The planning criteria taken into account in subtransmission system planning are: · Consumer and zone substation security of supply requirements · Zone substation location and capacity · Current ratings and fault ratings of network equipment · Economic rating of components · Feeder loading principles · Voltage selection · Voltage regulation · The forecast growth rate for electrical load at existing zone substations and the horizon year load density within specific geographic load areas related to the zone substations · Protection scheme design · Transformer and switchgear ratings for normal and contingency operation · Substation firm capacity · Overhead vs. underground construction · The need to optimise capital investment on the network, taking into consideration maintenance expenses · System performance under emergency conditions.

6.2.1 Security Of Supply Standards Security of supply requirements for zone substations are set out in Powerco BMS Standard 334S001, “Security of Supply Classification – Zone Substations”. Its requirements are as follows:

Zone substations are classified for security according to Table 15 below:

Table 15: Zone Substation Security Classification Substation Targeted Duration for Targeted Duration for Classification First Interruption Second Interruption AAA None Repair time AA+ 15 seconds Repair time AA 45 minutes Repair time A1 Isolation time Repair time A2 Repair time Repair time

Details of the classifications are as follows:

AAA: Supply is uninterrupted in the event of the outage of one major element of the subtransmission network. Load can be transferred to other substations without interruption by switching on the network if necessary to avoid exceeding ratings.

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AA+ Supply may be lost in the event of the outage of one major element of the subtransmission network. Supply is restored automatically within 15 seconds by automatic switching at subtransmission or distribution level.

AA Supply may be lost in the event of the outage of one major element of the subtransmission network. Supply can be restored within 45 minutes by switching at subtransmission or distribution level.

A1 Supply may be lost in the event of the outage of one major element of the subtransmission network. Supply can be restored by switching after the faulted element is isolated.

A2 Supply may be lost in the event of the outage of one major element of the subtransmission network. Supply cannot be restored until the faulty element is repaired or replaced.

Table 16 below shows the criteria and selection process for zone substation security level. It shall be applied subject to economic and technical feasibility.

Table 16: Zone Substation Security Level Selection Load Type Zone Substation Maximum Demand < 1 MVA 1 – 5 MVA 5 – 12 MVA >12 MVA F1 AA AA AA+ AAA F2 AA AA AA+ AAA F3 AA AA AA AA F4 A1 A1 A1 n/a F5 A2 A2 n/a n/a

6.3 Planning Criteria – Medium Term Planning (Distribution Planning) This section describes the key planning criteria that have been adopted to guide the development of the distribution network. They are: · The need to meet Consumer Service targets and any agreed supply criteria · Industrial, commercial and residential developments affecting specific areas of supply · Loss minimisation through correct conductor selection and optimised switching configurations · Feeder loading principles · Feeder conductor grading · Feeder configuration (i.e. location of switches, interconnection with adjacent feeders, load constraints for spur lines) · Automation · Use of line reclosers and sectionalisers · Voltage regulation · Overhead vs. underground construction · The need for feeder rearrangements on the commissioning of new zone substations · Current ratings and fault ratings of network equipment · The forecast growth rate for electrical load · The need to optimise capital investment on the network, taking into consideration maintenance expenses · Protection scheme design · Performance under emergency conditions.

6.3.1 General Feeder Loading Principles With distribution at 11kV the load per feeder averages 3MVA but may go up to 4MVA. Working on the "two thirds" principle of design, feeders are generally rated for 6MVA or more maximum load. Lower ratings can be used in rural areas where lower load densities and capacities are expected to apply in the

Powerco Information Disclosure Asset Management Plan Electricity Network 2003 – 2012 Section Subject Date of Issue Page 6 Network Development and Lifecycle Asset Management Plan 30/06/02 38 long term. The 22 kV and 6.6 kV feeders are in lower load density areas, and do not normally carry loads of this magnitude.

6.3.2 Underground vs. Overhead Construction Powerco's policy on overhead v. underground construction is as follows: · Overhead lines in urban areas will be replaced with underground circuits at the end of their economic life, provided that funding for the uneconomic portion can be obtained from an outside source. · New urban circuits shall be constructed underground in accordance with the district plan. · New rural circuits will be constructed overhead unless there is a specific consumer request for underground, such as a rural lifestyle block subdivision. In this case the design must be in line with Powerco standards, and the full additional cost must be met by the consumer.

6.3.3 Feeder Configuration When considering the configuration of feeders, the ability of the feeder to meet the reliability performance targets, assuming it is properly maintained, is the overriding objective. The factors that affect reliability are the probability of a fault and the typical repair or restoration time. As the reliability of the equipment is governed by its condition and thus influenced by maintenance, the maintenance criteria have been set to ensure the repair or restoration time is sufficiently short to meet the required reliability given the inherent equipment reliability.

6.4 Load Demand Forecast The Powerco demand forecasts are largely based on historical load growth trends with reference to anticipated future regional development and growth, although the changing nature of some areas, particularly dairy farming areas, makes historical loads of limited use as a guide to future loads. The forecast has been prepared for each substation service area without disaggregation into market sectors (residential, commercial, industrial and agricultural).

Changing load patterns in the residential sector are likely to impact on future growth in peak demand. Energy efficient appliances and an increasing use of gas may reduce the rate of growth and are probably already doing so. This has been taken into account in the forecast. The future pattern of load control use may also affect load growth, and this will be monitored for future revisions of this plan.

The effects of possible future run down of gas supply could be considered in the load forecast. However, with the heavy investment made and continuing to be made in the gas network, any run down in gas supply should be slow and well publicised. Therefore, if evidence showed that a rundown in gas supply were to become clearly imminent, it can be accommodated within future revisions of the plan.

Also of potential significance is the prospect of further changes in the major industries in Powerco's service area. Such changes are hard to predict and will be monitored and taken into account in future plans, as the changes occur.

6.4.1 The Forecast Forecast peak power demands for each zone substation in the Powerco network are as follows:

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Table 17.1: Forecast Maximum Demands for Taranaki Zone Substations Substation Annual 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Growth % Bell Block 3 19.2 19.7 20.3 20.9 21.6 22.2 22.9 23.6 24.3 25 25.7 26.5 27.3 28.1 29 29.8 Cambria 2 12.8 13 13.3 13.5 13.8 14.1 14.4 14.6 14.9 15.2 15.5 15.9 16.2 16.5 16.8 17.2 Cardiff 1 1.5 1.5 1.5 1.6 1.6 1.6 1.6 1.6 1.6 1.7 1.7 1.7 1.7 1.7 1.7 1.8 City 2 15.6 15.9 16.2 16.6 16.9 17.2 17.6 17.9 18.3 18.7 19 19.4 19.8 20.2 20.6 21 Cloton Rd 2 7.1 8.2 8.4 8.6 8.7 8.9 9.1 9.2 9.4 9.6 9.8 10 10.2 10.4 10.6 10.8 Douglas 1 1.9 1.9 2 2 2 2 2 2.1 2.1 2.1 2.1 2.1 2.2 2.2 2.2 2.2 Eltham 1 8.1 8.2 8.2 8.3 8.4 8.5 8.6 8.7 8.7 8.8 8.9 9 9.1 9.2 9.3 9.4 Inglewood 1 4 4.1 4.1 4.2 4.2 4.2 4.3 4.3 4.4 4.4 4.5 4.5 4.6 4.6 4.6 4.7 Kaponga 1 3.2 3.3 3.3 3.3 3.4 3.4 3.4 3.5 3.5 3.5 3.6 3.6 3.6 3.7 3.7 3.8 Kapuni 1 6.3 6.3 6.4 6.5 6.5 6.6 6.6 6.7 6.8 6.8 6.9 7 7.1 7.1 7.2 7.3 Livingstone 1 2.7 2.8 2.8 2.8 2.8 2.9 2.9 2.9 3 3 3 3 3.1 3.1 3.1 3.2 Manaia 1 5.2 5.2 5.3 5.3 5.4 5.4 5.5 5.5 5.6 5.6 5.7 5.7 5.8 5.9 5.9 6 McKee 1 1.2 1.2 1.2 1.2 1.2 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.4 2 Motukawa 1 2.1 2.1 2.2 2.2 2.2 2.2 2.3 2.3 2.3 2.3 2.3 2.4 2.4 2.4 2.4 2.5 Ngariki 1 1.2 1.2 1.2 1.2 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.4 1.4 1.4 1.4 1.4 Pungarehu 1 3.2 3.3 3.3 3.3 3.4 3.4 3.4 3.5 3.5 3.5 3.6 3.6 3.6 3.7 3.7 3.8 Tasman 1 8.1 8.2 8.2 8.3 8.4 8.5 8.6 8.7 8.7 8.8 8.9 9 9.1 9.2 9.3 9.4 Waihapa 0 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 Waitara East 1 5.2 5.2 5.3 5.3 5.4 5.4 5.5 5.5 5.6 5.6 5.7 5.7 5.8 5.9 5.9 6 Waitara West 1 4.3 4.4 4.4 4.5 4.5 4.6 4.6 4.7 4.7 4.7 4.8 4.8 4.9 4.9 5 5 Whareroa 1 3.7 3.8 3.8 3.9 3.9 3.9 4 4 4 4.1 4.1 4.2 4.2 4.3 4.3 4.3 Carrington GXP 11kV 2 19 19.4 19.7 20.1 20.5 20.9 21.4 21.8 22.2 22.7 23.1 23.6 24.1 24.5 25 25.5 Moturoa GXP 2 14.4 14.7 15 15.3 15.6 15.9 16.2 16.5 16.9 17.2 17.5 17.9 18.2 18.6 19 19.4

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Table 17.2: Forecast Maximum Demands for Wanganui Zone Substations Substation Annual 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Growth % Arahina 1 7.3 7.3 7.4 7.5 7.6 7.6 7.7 7.8 7.9 8 8 8.1 8.2 8.3 8.4 8.4 Beach Rd 5 8.3 8.7 9.1 9.6 10.1 10.6 11.1 11.7 12.3 12.9 13.5 14.2 14.9 15.6 16.4 17.2 Blink Bonnie 1 3.6 3.6 3.7 3.7 3.7 3.8 3.8 3.9 3.9 3.9 4 4 4.1 4.1 4.1 4.2 Bulls 1 3.5 3.5 3.6 3.6 3.6 3.7 3.7 3.8 3.8 3.8 3.9 3.9 3.9 4 4 4.1 Castlecliff 5 10.4 10.9 11.5 12 12.6 13.3 13.9 14.6 15.4 16.1 16.9 17.8 18.7 19.6 20.6 21.6 Hatricks Wharf 1.5 11.5 11.7 11.8 12 12.2 12.4 12.6 12.8 13 13.1 13.3 13.5 13.7 14 14.2 14.4 Kai Iwi 1 2.4 2.4 2.4 2.5 2.5 2.5 2.5 2.6 2.6 2.6 2.7 2.7 2.7 2.7 2.8 2.8 Peat St 2 8 8.1 8.2 8.4 8.6 8.8 9 9.1 9.3 9.5 9.7 9.9 10 10.3 10.4 10.7 Pukepapa 1 3.4 3.4 3.5 3.5 3.6 3.6 3.6 3.7 3,7 3.8 3.8 3.8 3.9 3.9 3.9 4 Rata 0.5 2.6 2.6 2.6 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.8 2.8 2.8 2.8 2.8 Roberts Ave 1 3.7 3.8 3.8 3.9 3.9 3.9 4 4 4 4.1 4.1 4.2 4.2 4.3 4.3 4.3 Taihape 1 4.5 4.5 4.6 4.6 4.7 4.7 4.8 4.8 4.9 4.9 5 5 5.1 5.1 5.2 5.2 Taupo Quay 1.5 7.7 7.8 7.9 8.1 8.2 8.3 8.4 8.6 8.7 8.8 9 9.1 9.2 9.4 9.5 9.6 Waiouru varies 3.2 3.1 3 2.9 2.8 2.8 2.8 2.7 2.7 2.7 2.7 2.6 2.6 2.6 2.6 2.6 Wanganui East 1.5 5.4 5.5 5.5 5.6 5.7 5.8 5.9 6 6.1 6.2 6.2 6.3 6.4 6.5 6.6 6.7 Mataroa (future) 1 0 2 2 2 2.1 2.1 2.1 2.1 2.2 2.2 2.2 2.2 2.3 2.3 2.3 2.3 Ohakune GXP 1 2 2 2.1 2.1 2.1 2.1 2.1 2.2 2.2 2.2 2.2 2.2 2.3 2.3 2.3 2.3 Waverley GXP 1 3.5 3.6 3.6 3.6 3.7 3.7 3.8 3.8 3.8 3.9 3.9 3.9 4 4 4.1 4.1

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Table 17.3: Forecast Maximum Demands for Manawatu Zone Substations Substation Annual 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Growth % Alfredton 0.7 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.7 0.7 0.7 0.7 0.7 Fielding 1.2 18.2 18.4 18.7 18.9 19.1 19.3 19.6 19.8 20 20.3 20.5 20.8 21 21.3 21.5 21.8 Kairanga 2.4 14.4 14.8 15.1 15.5 15.9 16.3 16.6 17 17.5 17.9 18.3 18.7 19.2 19.7 20.1 20.6 Keith St 2.9 9.9 10.2 10.5 10.8 11.1 11.4 11.7 12.1 12.4 12.8 13.1 13.5 13.9 14.3 14.7 15.2 Kelvin Grove 2.8 9.8 10 10.3 10.6 10.9 11.2 11.5 11.8 12.2 12.5 12.9 13.2 13.6 14 14.4 14.8 Kimbolton 0.9 2.2 2.2 2.3 2.3 2.3 2.3 2.3 2.4 2.4 2.4 2.4 2.4 2.5 2.5 2.5 2.5 Main Street 1.9 23.4 23.9 24.3 24.8 25.3 25.7 26.2 26.7 27.2 27.8 28.3 28.8 29.4 29.9 30.5 31.1 Mangamutu 1.4 6.6 6.7 6.8 6.9 7 7.1 7.2 7.3 7.4 7.5 7.6 7.7 7.8 7.9 8 8.1 Milson 3.1 13 13.4 13.8 14.2 14.7 15.1 15.6 16.1 16.6 17.1 17.6 18.2 18.7 19.3 19.9 20.5 Parkville 0.7 1.8 1.8 1.8 1.9 1.9 1.9 1.9 1.9 1.9 1.9 1.9 2 2 2 2 2 Pascal Street 1.6 14.6 14.9 15.1 15.3 15.6 15.8 16.1 16.3 16.6 16.9 17.1 17.4 17.7 18 18.3 18.6 Pongoroa 0.6 1 1 1 1 1 1 1 1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 Sanson 1.6 6.3 6.4 6.5 6.6 6.7 6.8 6.9 7 7.2 7.3 7.4 7.5 7.6 7.7 7.9 8 Turitea 3.5 8.9 9.2 9.5 9.9 10.2 10.6 10.9 11.3 11.7 12.1 12.6 13 13.5 13.9 14.4 14.9

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Table 17.4: Forecast Maximum Demands for Wairarapa Zone Substations Substation Annual 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Growth % Akura 1 10.6 10.8 10.9 11 11.1 11.3 11.4 11.5 11.6 11.7 11.8 12 12.1 12.2 12.3 12.4 Awatoitoi 1 0.9 0.9 0.9 0.9 0.9 1 1 1 1 1 1 1 1 1 1 1.1 Chapel 1 11.9 12.2 12.3 12.4 12.6 12.7 12.8 12.9 13.1 13.2 13.3 13.5 13.6 13.7 13.9 14 Clareville 1 8 8.4 8.5 8.5 8.6 8.7 8.8 8.9 9 9.1 9.2 9.3 9.3 9.4 9.5 9.6 Featherston 1 4.8 4.9 5 5 5.1 5.1 5.2 5.2 5.3 5.3 5.4 5.4 5.5 5.5 5.6 5.6 Gladstone 1 0.7 0.7 0.7 0.7 0.7 0.7 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 Hau Nui 0 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6 Kempton 1 4.1 4.2 4.2 4.3 4.3 4.3 4.4 4.4 4.5 4.5 4.6 4.6 4.7 4.7 4.8 4.8 Martinborough 1 2.6 2.7 2.7 2.8 2.8 2.8 2.8 2.9 2.9 2.9 3 3 3 3 3.1 3.1 Norfolk 1 5.7 5.7 5.8 5.8 5.9 6 6 6.1 6.1 6.2 6.3 6.3 6.4 6.5 6.5 6.6 Te Ore Ore 1 5.4 5.5 5.6 5.6 5.7 5.7 5.8 5.9 5.9 6 6 6.1 6.2 6.2 6.3 6.3 Tinui 1 0.8 0.8 0.8 0.8 0.8 0.8 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 Tuhitarata 1 1.4 1.4 1.4 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.6 1.6 1.6 1.6 1.6 1.6

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It should be noted that these load growths are for the area currently supplied by the substation in question. In some cases it will not be practicable to reinforce the substation to accommodate the 2017 load, and load transfers and network reinforcement will be required to accommodate it. These will be programmed as this plan is reviewed year by year,

Comparing the load growth projections against territorial local authority plans and other demographic information such as census data, real estate and property development forecasts, business forecasts and national economic projections, indicates that these forecasts appear adequately accurate for planning purposes.

6.5 Non-Asset Solutions Powerco has an active policy of investigating and where appropriate recommending or adopting non- asset solutions. Presently the following solutions have been implemented: · Load transfer through the distribution network is considered prior to any substation capacity upgrade. · Demand side management is encouraged through demand based network charges. · Load control is used to reduce demand peaks.

The network has been assessed to determine if any existing assets would be better served by alternative providers. At the time of writing no such assets have been identified. The situation will continue to be actively monitored. In the past Powerco has provided solar powered installations in place of network extensions for some remote small loads such as electric fence units. All opportunities will continue to be monitored and the current policy of encouraging non-asset-based solutions will remain in place.

6.6 Adoption of New Technology Powerco has an active programme in keeping up with the latest technical innovations and where appropriate introducing these onto its system. Recent new technology adopted by Powerco includes the following: · The introduction of numerical protection relays · The use of remotely operated distribution switchgear · The use of spread-spectrum radio, microwave and optical fibre communication for SCADA · The use of handheld electronic data capture devices for inspection and maintenance work · The use of a circuit breaker profile logger for circuit breaker condition monitoring. · The use of infra-red, ultrasonic and partial discharge techniques. · The use of a mobile substation to remove the necessity of several zone substation upgrades and to improve network utilisation is being considered.

6.7 Acquisition of New Assets Where appropriate Powerco will continue to acquire new assets where it is economically viable. This may be by acquiring additional networks, sections of network owned by consumers or new subdivisions. Those carrying out subdivision development have shown little inclination to retain ownership and it is anticipated that this trend will continue for the duration of this plan.

6.8 Redeployment, Upgrade and Disposal of Existing Assets Powerco does not anticipate disposing of any major network assets for the duration of the plan other than obsolete or superseded equipment. Equipment that is redundant at a particular location will be refurbished and returned to service in an alternative location more appropriate to its capabilities, provided that it has sufficient life remaining for refurbishment to be economic. Any serviceable equipment that does not have a potential use within a reasonable period will be disposed of.

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6.9 Long Term Development Plan (Subtransmission Development Plan)

6.9.1 Introduction A Long Term Development Plan separate from this Asset Management Plan has been prepared. Its main points are summarised below.

Development of the subtransmission system over the planning period is being determined from the general Asset Management Plan drivers, criteria for long-term planning and forecast load growth. Where drivers or planning criteria in any areas are not satisfied, then development work is analysed and programmed where required.

The following areas are being considered: · The development of the subtransmission system with particular reference to the location, capacity and security requirements foreseen in the horizon year · Voltage selection · Capacity and security of grid exit points · Other matters including neutral point earthing, losses, reactive power and protection. · Zone substation interconnections at distribution level.

6.9.2 Planning Period A planning period of 15 years (from 1 April 2002) was adopted for the purpose of this plan. This period was chosen as it is of sufficient length for the development of the subtransmission system to be outlined.

6.9.3 Assessment of Suitability of System For Present Needs and Analysis of Development Options

6.9.3.1 General Comments The present network configuration allows some operational flexibility, but the level of security of supply offered in a few areas does not comply with the security of supply criteria.

The mixed radial/ring configuration increases the security of supply, but also increases fault levels and protection system complexity when operated as a ring.

6.9.3.2 Grid Exit Points The 11 kV switchgear at Carrington GXP 11 kV bus is over 45 years old, and is due for replacement or removal. The option of building a new zone substation to replace it is under investigation.

The outdoor 33 kV bus at Stratford GXP is about to be replaced with indoor switchgear.

A comprehensive load management strategy is being developed to determine future load control requirements.

The possible purchase of Moturoa GXP from Transpower is being discussed

No other development or upgrading of GXPs is programmed or planned by Transpower in the present asset management cycle. Possible overloading of 110 kV lines out of Hawera GXP will be managed by Transpower constraining local generation. Analysis indicates that the capacity at the points of supply will be suitable for Powerco’s needs for this planning period.

6.9.3.3 Zone Substation Transformer Utilisation The following tables show transformer utilisation for 2002 and forecast Utilisation for 2007 and 2012 on the basis of the presently installed transformers. Load data is taken from load forecast tables . This data

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Table 18.1: Taranaki Zone Substation Transformer Utilisation Data Substation XFMR ONAN 2002 % 2007 2012 % Util % Util % Util Config. Cap. Load growth Load Load 2002 2007 2012 Bell Block 1 2 x 9.4/19.3 18.8 19.2 3 22.2 25.7 102% 118% 137% Cambria 2 X 10 20 12.8 2 14.1 15.5 64% 71% 78% Cardiff 1 x 3 3 1.5 1 1.6 1.7 50% 53% 57% City 2x10.6/21.2 21.2 15.6 2 17.2 19 74% 81% 90% Cloton Rd 2 x 10/13 20 8.1 2 8.9 9.8 41% 45% 49% Douglas 1 x 5 5 1.9 1 2 2.1 38% 40% 42% Eltham 2 x 7.5/10 15 8.1 1 8.5 8.9 54% 57% 59% Inglewood 2 x 5 10 4 1 4.2 4.5 40% 42% 45% Kaponga 2 x 2.5 5 3.2 1 3.4 3.6 64% 68% 72% Kapuni 2 X 5 10 6.3 1 6.6 6.9 63% 66% 69% Livingstone 2 x 2.5 5 2.7 1 2.9 3 54% 58% 60% Manaia 1 X 5/6.25 5 5.2 1 5.4 5.7 104% 108% 114% McKee 2 x 1.25 2.5 1.2 1 1.3 1.3 48% 52% 52% Motukawa 1 x 2.5 2.5 2.1 1 2.2 2.3 84% 88% 92% Ngariki 1 X 5/6.25 5 1.2 1 1.3 1.3 24% 26% 26% Pungarehu 2 X 3/4 6 3.2 1 3.4 3.6 53% 57% 60% Tasman 2 X 5 10 8.1 1 8.5 8.9 81% 85% 89% Waihapa 1x1.25,1x2.5 3.75 1.2 0 1.2 1.2 32% 32% 32% Waitara East 2 x 5/9 10 5.2 1 5.4 5.7 52% 54% 57% Waitara West 2 x 5 10 4.3 1 4.6 4.8 43% 46% 48% Whareroa 1 x 10 10 3.7 1 3.9 4.1 37% 39% 41% 197.75 118.8 128.8 139.6 60% 65% 71%

Table 18.2: Wanganui Zone Substation Transformer Utilisation Data Substation Xfmr ONAN 2002 % 2007 2012 % Util % Util % Util Config. Cap. Load growth Load Load 2002 2007 2012 Arahina 1 x 10/12.5 10 7.3 1 7.6 8 73% 76% 80% Beach Rd 1 x 10 10 8.3 5 10.6 13.5 83% 106% 135% Blink Bonnie 1 x 5 5 3.6 1 3.8 4 72% 76% 80% Bulls 1 x 7.5 7.5 3.5 1 3.7 3.9 47% 49% 52% Castlecliff 1x7.5, 15 10.4 5 13.3 16.9 69% 89% 113% 1x7.5/10 Hatricks Wharf 1 x 10 10 11.5 1.5 12.4 13.3 115% 124% 133% Kai Iwi 1 x 5 5 2.4 1 2.5 2.7 48% 50% 54% Peat St 1 x 7.5/10 7.5 8 2 8.8 9.7 107% 117% 129% Pukepapa 1 x 10/12.5 10 3.4 1 3.6 3.8 34% 36% 38% Rata 1 x 7.5 7.5 2.6 0.5 2.7 2.7 35% 36% 36% Roberts Ave 1 x 7.5/10 7.5 3.7 1 3.9 4.1 49% 52% 55% Taihape 1 x 7.5/10 7.5 4.5 1 4.7 5 60% 63% 67% Taupo Quay 1 x 10/12.5 10 7.7 1.5 8.3 9 77% 83% 90% Waiouru 1 x 7.5 7.5 3.2 varies 2.8 2.7 43% 37% 36% Wanganui East 1 x 7.5 7.5 5.4 1.5 5.8 6.2 72% 77% 83% 127.5 85.5 94.5 105.5 67% 74% 83%

Table 18.3: Manawatu Zone Substation Transformer Utilisation Data Substation Xfmr ONAN 2002 % 2007 2012 % Util % Util % Util Config. Cap. Load growth Load Load 2002 2007 2012 Alfredton 1 x 1.5 1.5 0.6 0.7 0.6 0.6 40% 40% 40% Feilding 2 x 16/24 32 18.2 1.2 19.3 20.5 57% 60% 64% Kairanga 2 x 12.5/17 25 14.4 2.4 16.3 18.3 58% 65% 73% Keith St 2 x 7.5 15 9.9 2.9 11.4 13.1 66% 76% 87% Kelvin Grove 2 x 12.5/17 25 9.8 2.8 11.2 12.9 39% 45% 52% Kimbolton 1 x 3 3 2.2 0.9 2.3 2.4 73% 77% 80% Main St 2 x 20 40 23.4 1.9 25.7 28.3 59% 64% 71% Mangamutu 2 x 5/6.25 10 6.6 1.4 7.1 7.6 66% 71% 76% Milson 2 x 12.5/17 25 13 3.1 15.1 17.6 52% 60% 70% Parkville 1 x 3 3 1.8 0.7 1.9 1.9 60% 63% 63%

1 In June 2002, MCK Metals announced the imminent closure of its brass and copper plant. As the effect of this is not yet known, it is not included in the load figures.

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Substation Xfmr ONAN 2002 % 2007 2012 % Util % Util % Util Config. Cap. Load growth Load Load 2002 2007 2012 Pascal St 2 x 20 40 14.6 1.6 15.8 17.1 37% 40% 43% Pongaroa 1 x 3 3 1 0.6 1 1.1 33% 33% 37% Sanson 2 x 7.5 15 6.3 1.6 6.8 7.4 42% 45% 49% Turitea 2 x 7.5 15 8.9 3.5 10.6 12.6 59% 71% 84% 252.5 130.7 145.1 161.4 52% 57% 64%

Table 18.4: Wairarapa Zone Substation Transformer Utilisation Data Substation Xfmr ONAN 2002 % 2007 2012 % Util % Util % Util Config. Cap. Load growth Load Load 2002 2007 2012 Akura 2 x 7.5/10 15 10.6 1 11.3 11.8 71% 75% 79% Awatoitoi 1 x 3 3 0.9 1 1 1 30% 33% 33% Chapel 2 x 11.5/23 23 11.9 1 12.7 13.3 52% 55% 58% Clareville 2 x 7.5/10 15 8 1 8.7 9.2 53% 58% 61% Featherston 1 x 5/6.25 10 4.8 1 5.1 5.4 48% 51% 54% Gladstone 1 x 1.5 1.5 0.7 1 0.7 0.8 47% 47% 53% Hau Nui 1 x 5/6.25 5 3.6 0 3.6 3.6 72% 72% 72% Kempton 1 x 5/6.25 5 4.1 1 4.3 4.6 82% 86% 92% Martinborough 1 x 5/6.25 5 2.6 1 2.8 3 52% 56% 60% Norfolk 2 x 5/6.25 10 5.7 1 6 6.3 57% 60% 63% Te Ore Ore 1 x 5/6.25 5 5.4 1 5.7 6 108% 114% 120% Tinui 1 x 1.5 1.5 0.8 1 0.8 0.9 53% 53% 60% Tuhitarata 1 x 3 3 1.4 1 1.5 1.6 47% 50% 53% 102 60.5 64.2 67.5 59% 63% 66%

6.9.3.4 Zone Substation Capacity and Security Tables 19.1 to 19.4 below summarise the zone substation capacities and security of supply levels. Each of the substations is then discussed individually and the development requirements presented.

Table 19.1: Taranaki Substation Maximum Demands and Transfer Capacities Substation Xfmr Feeder S/G Sub Sub %of 2003 Desired Ratings Firm Transfer Firm Class MD Sub Security Security MVA Cap Cap Cap Cap 2002 Class of Class MVA MVA MVA MVA Cap Supply Bell Block 2 x 9.4/19.3 19.3 4 22.9 19.3 19.2 99.4 AAA AAA Cambria 2 X 10 10 6 22.9 10 12.8 128.0 AA AAA Cardiff 1 x 3 0 1.5 7.6 1.5 1.5 100.0 A1 A1 City 2 x 10.6/21.2 21.2 8 22.9 21.2 15.6 73.6 AAA AAA Cloton Rd 2 x 10/13 13 3.5 22.9 16.5 8.12 49.1 AA AA Douglas 1 x 5 0 2 22.9 2 1.9 95.0 A1 A1 Eltham 2 x 7.5/10 10 0 15.2 10 8.1 81.0 AAA AAA Inglewood 2 x 5 5 1 14.2 6 4.0 66.7 AA AA Kaponga 2 x 2.5 2.5 1.0 7.6 3.5 3.2 91.4 AA AA Kapuni 2 X 5 5 1.5 22.9 6.5 6.3 96.9 AA AA Livingstone 2 x 2.5 2.5 0 7.6 2.5 2.7 108.0 AA AA Manaia 1 X 5/6.25 0 5 11.4 5 5.2 104.0 A2 AA McKee 2 x 1.25 1.25 0 7.6 1.25 1.2 96.0 A1 A1 Motukawa 1 x 2.5 0 1.5 4.6 1.5 2.1 140.0 A2 A1 Ngariki 1 X 5/6.25 0 3 7.6 3 1.2 40.0 AA AA Pungarehu 2 X 3/4 4 1.6 15.2 5.6 3.2 57.1 AA AA Tasman 2 X 5 5 3 22.9 8 8.1 101.3 AA AA Waihapa 1x1.25, 1x2.5 1.25 0 7.6 1.25 1.2 96.0 A2 A2 Waitara East 2 x 5/9 9 5.1 23.8 14.1 5.2 39.7 AA AA Waitara West 2 x 5 5 4.3 23.8 9.3 4.3 46.2 AA AA Whareroa 1 x 10 0 3.7 7.6 3.7 3.7 100.0 AA AA

2 Load from Midhurst Substation (disestablished) added

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Table 19.2: Wanganui Substation Maximum Demands and Transfer Capacities Substation Xfmr Feeder S/G Sub Sub %of 2003 Desired Ratings Firm Transfer Firm Class MD Sub Security Security MVA Cap Cap Cap Cap 2002 Class of Class MVA MVA MVA MVA Cap Supply Arahina 1 x 10/12.5 0 7.2 22.9 7.2 7.3 101.4 AA AA Beach Rd 1 x 10 0 4.2 22.9 4.2 8.3 197.6 A2 AA+ Blink Bonnie 1 x 5 0 3.6 23.8 3.6 3.6 100.0 AA AA Bulls 1 x 7.5 0 1.6 12 1.6 3.5 218.8 A2 A1 Castlecliff 1x7.5, 1x7.5/10 7.5 2.4 15.2 9.9 10.4 105.0 AA AA+ Hatricks Wharf 1 x 10 0 10.9 15.2 10.9 11.5 115.0 AA AAA Kai Iwi 1 x 5 0 2.4 22.9 2.4 2.4 100.0 A2 AA Peat St 1 x 7.5/10 0 7.8 23.8 7.8 8.0 102.5 AA AA+ Pukepapa 1 x 10/12.5 0 3.4 22.9 3.4 3.4 100.0 AA AA Rata 1 x 7.5 0 2.1 7.6 2.1 2.6 123.8 A2 A1 Roberts Ave 1 x 7.5/10 0 3.9 22.9 3.9 3.7 94.9 AA AA Taihape 1 x 7.5/10 0 0.1 22.9 0.1 6.1 none A2 AA Taupo Quay 1 x 10/12.5 0 6 23.8 6 7.7 128.3 A2 AAA Waiouru 1 x 7.5 0 0.1 15.2 0.1 3.2 none A2 A1 Wanganui East 1 x 7.5 0 3.8 23.8 3.8 5.4 142.1 A2 AA

Table 19.3: Manawatu Substation Maximum Demands and Transfer Capacities Substation Xfmr Feeder S/G Sub Sub %of 2003 Desired Ratings Firm Transfer Firm Class MD Sub Security Security MVA Cap Cap Cap Cap 2002 Class of Class MVA MVA MVA MVA Cap Supply Alfredton 1 x 1.5 0 1.1 7.6 1.1 0.6 54.5 A1 A1 Feilding 2 x 16/24 24 3 30.4 24 18.2 75.8 AA AAA Kairanga 2 x 12.5/17 17 8.8 22.9 17 14.4 84.7 AA AAA Keith St 2 x 7.5 7.5 7.2 30.4 7.5 9.8 131 AA AAA Kelvin Grove 2 x 12.5/17 17 7 22.9 17 9.7 57.1 AA AAA Kimbolton 1 x 3 0 1.5 12 1.5 2.2 146.6 A2 A2 Main St 2 x 20 20 8 30.4 20 23.4 117 AA AAA Mangamutu 2 x 5/6.25 6.25 2 22.9 8.25 6.5 78.9 AA AA Milson 2 x 12.5/17 17 7.1 22.9 17 12.9 75.9 AAA AAA Parkville 1 x 3 0 1.8 7.6 1.8 1.8 100 A1 A1 Pascal St 2 x 20 20 8.3 30.4 20 14.6 73 AA AAA Pongaroa 1 x 3 0 1.3 7.6 1.3 1 76.9 A1 A1 Sanson 2 x 7.5 0 4.1 15.2 4.1 6.2 151.2 A2 AA Turitea 2 x 7.5 3 7.5 2 22.9 7.54 8.9 118.7 AA AAA

Table 19.4: Wairarapa Substation Maximum Demands and Transfer Capacities Substation Xfmr Feeder S/G Sub Sub %of 2003 Desired Ratings Firm Transfer Firm Class MD Sub Security Security MVA Cap Cap Cap Cap 2002 Class of Class MVA MVA MVA MVA Cap Supply Akura 2 x 7.5/10 10 7 15.4 10 10.6 103.0 AAA AAA Awatoitoi 1 x 3 0 1.2 4.8 1.2 0.9 75.0 A2 A1 Chapel 2 x 11.5/23 23 8 24 23 11.9 50.0 AAA AAA Clareville 2 x 7.5/10 10 0 15.4 10 8 76.0 AA AA+ Featherston 1 x 5/6.25 0 2.5 15.4 2.5 4.8 184.0 A1 AA Gladstone 1 x 1.5 0 1 4.8 1 0.7 70.0 A1 A1 Hau Nui 1 x 5/6.25 0 1 7.7 1 45 400.0 A2 A1 Kempton 1 x 5/6.25 0 2.8 15.4 2.8 4.1 139.0 A2 AA Martinborough 1 x 5/6.25 0 2.3 15.4 2.3 2.6 109.0 A2 AA Norfolk 2 x 5/6.25 6.25 4 15.4 6.25 5.7 91.2 AA AAA

3 Being replaced with 12.5/17 MVA units 4 12.5/17 MVA units are being installed which will improve class capacity from 7.5 to 17 MVA 5 4 MVA is wind farm export. Other load < 1 MVA

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Substation Xfmr Feeder S/G Sub Sub %of 2003 Desired Ratings Firm Transfer Firm Class MD Sub Security Security MVA Cap Cap Cap Cap 2002 Class of Class MVA MVA MVA MVA Cap Supply Te Ore Ore 1 x 5/6.25 0 5 15.4 5 5.4 104.0 A2 AA Tinui 1 x 1.5 0 1 4.8 1 0.8 80.0 A1 A1 Tuhitarata 1 x 3 0 1.5 4.8 1.5 1.4 93.0 AA A1

Many substations showing lower than desired security levels are only marginally lower, and upgrading will proceed along with other substation work, but urgent attention is being given to those supplying industrial or commercial loads, particularly in Wanganui. These don't reflect overloaded transformers but unserved load after a failure.

6.9.3.5 Taranaki Zone Substation City substation supplies the central business district and surrounding residential area of New Plymouth. Population is static with little building activity, but there is capacity for development in the central business district, where a number of retail and office premises are vacant and several prime sites are occupied by used car dealers. Its capacity is expected to be adequate for the planning period.

Bell Block substation supplies the Bell Block industrial area, and the nearby residential and surrounding rural areas. The area offers flat industrial zoned sites, conveniently sited for access to highway, port and rail at reasonable cost, so further industrial load growth is possible. One major consumer in the area dominates by taking approximately 30% of firm capacity of the zone substation. Bell Block substation has two 11.5/23 MVA transformers, but these are rated at 5OC. At 20OC, a rating of 9.4/19.3 MVA has been calculated. On the basis of this rating, Bell Block is loaded to its firm capacity. Load transfer of 3 MVA to Waitara West is now possible, and the installation of a 6.6/11 kV autotransformer at Inglewood will enable load to be transferred to Inglewood in an emergency. During June 2002, MCK Metals has announced the imminent closure of its copper and brass plant. The effect of this is not yet known, but may result in a load reduction of up to 5 MVA. Consequently it is not included in the load growth figures.

Carrington GXP 11 kV supplies the southern residential area of New Plymouth and the rural area to the south of the city. There is some residential building going on in the area, and additional residential sections are being subdivided. The bus is loaded beyond its firm capacity, and significant load shedding is required during winter to prevent overloading. The 11 kV switchgear is over 45 years old. Consideration is being given to replacing this GXP bus with a new zone substation.

Moturoa GXP 11 kV is owned by Transpower, although Powerco owns some of the equipment in it and the 33 kV cables supplying it. Powerco also has an interest in the transformers, having paid 2,100 UK pounds in 1971 to have 11.5/23 MVA transformers installed instead of 10 MVA units. Moturoa substation supplies the port area of New Plymouth and the western part of the New Plymouth residential area. It also supplies the rural area westward to Oakura. Its capacity is adequate for the planning period. Discussions have been held with Transpower regarding Powerco purchasing this substation.

Waitara West substation supplies the Waitara town area and some nearby rural area. It also provides supply to the remaining load at the Waitara freezing works. Load growth is expected to be small, although the blast freezers at the previously closed Waitara freezing works complex are being operated, and more development is proceeding on the site. Its capacity is expected to be adequate for the planning period unless there is significant industrial development.

Waitara East substation supplies the rural area to the east of Waitara, and all the area north towards Mt Messenger. Little load growth is expected and its capacity is expected to be adequate for the planning period.

McKee substation supplies the McKee petroleum production station and the surrounding rural area. Although it is over its firm capacity, it is expected to be adequate the planning period. However the transformers are over 45 years old, and may require replacement in that time.

Inglewood substation supplies Inglewood township and the surrounding rural area. Its capacity is expected to be adequate for the planning period.

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Motukawa substation is located at Trustpower's Motukawa power station site, and it supplies the surrounding rural area. Although it is over its firm capacity, it is expected to be adequate for the planning period. It will be disestablished if 6.6/11 kV conversion occurs.

Midhurst Substation has been disestablished, an replaced by an 11 kV / 6.6 kV transformer. Its 1 MVA load has been transferred to Cloton Rd Substation.

Cloton Rd substation supplies the commercial and residential areas of Stratford and the surrounding rural area. Population is static, with little building activity.

Douglas substation is situated near Douglas, to the east of Stratford. It supplies the rural area east of Stratford to beyond Whangamomona. There is lot of timber growing in this area. Electricity (and possibly gas ) needs could rise significantly if local milling is chosen. Its capacity is expected to be adequate for the planning period subject to the above.

Eltham substation supplies Eltham town and the surrounding rural area. A significant part of its load is taken by Riverlands freezing works and the Pastoral Foods dairy products factory. Load growth will largely depend on the requirements of these two consumers.

Waihapa substation is exclusively for supplying the Waihapa petroleum production station. Its load is not expected to increase.

Cardiff substation supplies the rural area to the west of Stratford. Its capacity is expected to be adequate during the planning period.

Kaponga substation supplies Kaponga and the surrounding rural area. It is beyond its firm capacity and loads in the area will be monitored to determine future needs.

Pungarehu substation supplies Pungarehu and the surrounding rural area. It also supplied a dairy factory which is now closed. Its capacity is expected to be adequate for the planning period.

Ngariki substation is on Ngariki Rd, between Opunake and Pungarehu. Its primary purpose is to provide a backup supply to the Maui Gas Terminal. It supplies the surrounding rural area. Its capacity is expected to be adequate for the planning period.

Tasman substation supplies Opunake town, the surrounding rural area and the Shell Todd Oil Services Maui Gas Terminal at Oaonui. Co-generation has been considered for this site in the past. It is loaded beyond its firm capacity and loads in the area will be monitored to determine future needs.

Manaia substation supplies the town of Manaia and the surrounding area. A significant part of its load is taken by one industrial consumer. It is a single transformer substation, backed up by 11 kV supply from Kapuni, but the backup is inadequate at times, and reinforcement is planned.

Kapuni substation supplies the rural area around Kapuni. It previously took co-generation load from the Natural Gas Corporation Kapuni site, and supplied the Lactose New Zealand plant. Its capacity is expected to be adequate for the planning period.

Cambria substation supplies the commercial and residential areas of Hawera and the immediate surrounding rural area. There is some growth in the Hawera area. It is over its firm capacity, and distribution network reinforcement may be carried out in conjunction with Whareroa substation relocation..

Whareroa substation is located on the Fontera Dairy Factory site. It previously supplied and accepted generation from Kiwi, but now supplies the rural area to the south of Hawera. Co-generation from a new oil and gas well site has commenced. The substation is configured for two transformers but only one is now installed. Loads in the area will be monitored to determine future needs. Access to the substation has become unsatisfactory, and rebuilding on another nearby site is planned.

Livingstone substation supplies Patea town and the surrounding area. Little load growth is expected. Although it is loaded slightly above its firm capacity, by using cyclic rating, its capacity is expected to be adequate for the planning period.

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6.9.3.6 Wanganui Zone Substations Hatricks Wharf and Taupo Quay substations supply the Wanganui CBD, and are configured to run in parallel. One transformer supports the other during outages and the peak demand will be monitored closely to ensure that overloading does not occur. The peak loads of these stations considered as a pair is over firm capacity, but 11 kV reinforcements in the Wanganui CBD will enable improved load transfer to Peat St Substation.

Peat St substation supplies a mix of residential and commercial loads, including the northern part of the Wanganui CBD. It is the main backup for Taupo Quay and Hatricks substations. When Mosston Substation is established, Mosston will pick up approximately 1.5 MVA of this load. The substation is configured for two transformers but only one is installed at present, resulting in part of the Wanganui CBD having only AA category security of supply.

Castlecliff and Beach Rd substations supply a large portion of the city’s industrial load. Several new industries have emerged over recent years and there has been strong load growth in this area. Castlecliff capacity will be adequate for the planning period, provided Mosston substation is commissioned by 2004. Beach Rd supplies Imlay freezing works and other industrial consumers from a single transformer, providing only AA category of supply. In the event of a subtransmission fault, backup supplies may be inadequate, and methods of improving this security are being investigated.

Roberts Ave substation is situated in Aramoho, supplying the Aramoho industrial area, and surrounding residential and rural areas. Its capacity is expected to be adequate for the planning period, but it has one transformer, providing only AA category security of supply.

Wanganui East substation supplies the residential area on the east side of the Whanganui river and rural area to the east of Wanganui. It is loaded beyond its firm capacity, and transformer reinforcement will be required during the planning period.

Blink Bonnie substation is situated to the east of Wanganui, adjacent to the Transpower Wanganui GXP. It supplies rural load to the south of Wanganui. Its capacity is expected to be adequate for the planning period.

Kai Iwi substation is situated to the north of Wanganui, and supplies the Wanganui City water pumping station and rural load. Its capacity is expected to be adequate for the planning period, but its 11 kV backup supply is marginal for starting the water supply pumps. Reinforcement proposals are being considered.

Arahina substation is situated at Marton, and supplies urban and rural load. Its capacity is expected to be adequate for the planning period.

Bulls substation supplies Bulls township and the surrounding and rural load. A proposed 11 kV link to Sanson will enable these two substations to support each other under fault conditions.

Pukepapa substation is situated adjacent to Transpower Marton GXP. It supplies rural load, but also provides a backstop for Arahina and Bulls substations. Its capacity is expected to be adequate for the planning period.

Rata Substation supplies Hunterville and the surrounding area. Its capacity is expected to be adequate for the planning period, but reinforcement is required to enable it to withstand a subtransmission fault.

Taihape substation is located in Taihape, and supplies urban and rural load. It has one transformer, and cannot be backfed in the event of a subtransmission fault, and a new Mataroa substation or an alternative is required to provide an adequate security level.

Waiouru substation is just south of Waiouru. It has one transformer, and cannot be backfed in the event of a subtransmission fault, and a new Mataroa substation or an alternative is required to provide an adequate security level.

6.9.3.7 Manawatu Zone Substations Alfredton, Parkville and Pongaroa substations have category A1 security. Each consists of a single transformer that has sufficient installed capacity to meet forecast load growth. No work is planned to reinforce the 11kV interconnection to Parkville substation at this stage. Powerco is considering

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Feilding substation has two transformers with a capacity of 2 x 16/24MVA which provide AAA security. It supplies commercial, industrial, residential and rural load. A third Bunnythorpe – Feilding 33kV circuit may be constructed during the planning period, but possible co-generation plant in the area may offset the need for it.

Kairanga substation load since 1997 has been static but projections indicate that additional capacity will be needed by 2010. Consideration will be given to replacing the transformers in 2010. The existing Bunnythorpe-Pascal and Kairanga-Milson circuits have been reconnected to become the Bunnythorpe- Milson and Kairanga-Pascal circuits, but they cannot run in this configuration until protection work is completed. When complete, this will have the benefit of providing two 33kV feeders to Milson from Bunnythorpe and two feeders to Kairanga from Linton (via Pascal St) providing AAA security to both of these zone substations

Keith St substation was at 200% of its AAA security rating firm capacity in 2001 due to temporary load transfer from Main St. The critical element is the 33/11kV transformer rating. The 33kV switchgear was replaced in 1999 as a result of the 33kV switchboard failure in June 1998. Keith St Substation will become the major point of supply for the 11kV network on the eastern side of Palmerston North, as the capacity and security can be improved more effectively at Keith St than at either Main St or Pascal St. Implementing the changes below will also provide AAA security at both Keith St and Main St.

The 2 x 9.4/19.3 MVA transformers ex Bell Block, or two new transformers, depending on future load requirements at Bell Block, will be installed at Keith St in 2003 and 2004.

Kelvin Grove substation forecast load remains within the existing firm capacity throughout the planning period. Further growth can be catered for by existing equipment. Upgrading of the protection to enable AAA supply security is being considered when a Kelvin Grove – Keith St line is installed.

Kimbolton substation firm capacity is adequate, with sufficient installed transformer capacity to the end of the planning period. Presently the substation does not have A1 security. Options are being investigated to improve the security to A1. The options being considered are: reinforcement of the 11kV system, installation of 11kV regulators, the purchase of a mobile 11kV regulator or the purchase or hiring of a mobile 33/11kV substation.

Main St substation transformer firm capacity is likely to be exceeded by 37% under the present configuration, but load transfer as described under Keith St above will reduce the load to within its firm capacity. Main Street 33kV configuration will remain in its present form meantime. The 11 kV switchboard was replaced during 2002 to enable SCADA control and to provide an adequate fault capacity. There are 2 x 20MVA transformers at Main Street, and the 11kV network will be configured to limit Main St Substation load to its firm capacity of 20 MVA.

Mangamutu Substation peak load has reduced since 1995, but there is still insufficient firm capacity to meet present and forecast demand. Load growth largely depends on dairy industry load at Pahiatua. Potential development of co-generation in this area will also have an impact on utilisation and capacity requirements at this substation. To improve security of supply, transformer capacity should be upgraded. It is proposed to use 2 x 7.5MVA upgraded to ONAF transformers ex Keith Street.

Milson substation may marginally exceed installed transformer ONAN capacity by the end of the planning period. Upgrading Milson and interconnecting it at 11kV with Pascal Street and Kairanga will be carried out when loads indicate it is necessary.

Pascal St substation was refurbished in 1999 to meet required security levels. 33kV and 11kV switchgear firm capacity has been upgraded following equipment availability from Longburn substation. AAA security has not yet been achieved at Pascal St due to the configuration of the 33kV feeders. 33 kV security can be achieved by installing a second 33kV circuit from Linton. Also, with the splitting of the Kairanga – Milson and Bunnythorpe – Pascal St lines to form Kairanga – Pascal St and Milson – Bunnythorpe lines would require that Pascal substation on-feed to Kairanga.

Sanson substation has adequate firm capacity to meet forecast demand. However the single 33 kV circuit supply configuration does not allow class AA security to be achieved. One alternative is a second 33kV line from Feilding or from Bulls to Sanson. Installation of 33kV circuit breakers would be required

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Turitea substation has adequate capacity to meet forecast demands. Co-generation in the area may have an impact on capacity requirements and will be assessed accordingly. Two 12.5/ 17 MVA transformers ex Fielding have been refurbished and are being installed in mid 2002. The 33 kV protection will be upgraded to enable AAA security to be achieved.

Tararua Wind Power (TWP) site began generation in November 1998 and was at full production of 31MW in May 1999. The wind farm has been configured in two groups of turbines (approximately 15MW each). The turbines are connected together by a 33kV cable network. Its capacity may be increased during the planning period. TWP can be connected to Kelvin Grove and/or Turitea.

6.9.3.8 Wairarapa Zone Substations Chapel and Akura substations supply the Masterton Central Business District, industrial and commercial areas, and a significant part of Masterton residential area. Their capacities are expected to be adequate for the planning period. Akura peak load is slightly above its firm capacity, but this plus projected growth can be handled by cyclic loading and load transfer.

Te Ore Ore substation is on the eastern edge of Masterton, and supplies a mix of residential and rural load. Its capacity is expected to be adequate for the planning period. It is slightly above its firm capacity, but this plus projected growth can be handled by cyclic loading and load transfer until around 2006, when a second transformer will be required.

Norfolk substation is situated a few kilometres south of Masterton. It supplies several MVA of load to a single large consumer, as well as a rural load. Its capacity is expected to be adequate for the planning period.

Tinui and Awatoitoi substations are situated in rural areas to the east of Masterton, towards Castlepoint, and they supply rural loads. Their capacities are expected to be adequate for the planning period.

Gladstone substation is situated in a rural area to the east of Carterton, and supplies rural load. Its capacity is expected to be adequate for the planning period.

Clareville substation supplies Carterton and the surrounding rural area. Its capacity is expected to be adequate for the planning period.

Kempton substation supplies Greytown and the surrounding rural area. Its capacity is expected to be adequate for the planning period.

Featherston substation supplies Featherston and the surrounding rural area. Irrigation loading continues to improve this substation's load factor. Its capacity is expected to be adequate for the planning period.

Martinborough substation supplies urban and rural load. New works in the area have not resulted in significant load increases, as most new loads are summer and weekend loads, occurring outside peak times. Its capacity is expected to be adequate for the planning period.

Tuhitarata substation is situated in the southern Wairarapa area, and supplies a rural load. Irrigation loading continues to improve this substation's load factor. Its capacity is expected to be adequate for the planning period.

Hau Nui substation is situated in south eastern Wairarapa, adjacent to the Genesis wind farm. Its primary purpose is to connect the wind farm output into the network, but it also supplies a small rural load. Its capacity is expected to be adequate for the planning period. It is 1.1 MVA above its firm capacity, but arrangements are in place to energise the 33 kV line at 11 kV to provide extra capacity if needed under fault conditions. This will be sufficient to supply consumers, but will not accept the full output of the Genesis wind farm, in the event of a transformer outage.

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6.9.3.9 11kV Load Transfer Capability The interconnection between 11kV feeders is adequate to provide category AAA security of supply to consumers in the city area of New Plymouth and large parts of the city areas of Wanganui, Palmerston North and Masterton. The remaining parts of these city areas have category AA security of supply, AA+ security will be installed progressively in those substations not meeting the security requirements set out in table 19. There is limited interconnection between the former Centralpower and Electro Power networks in Palmerston North, and additional interconnections are desirable for enhanced security. Waitara West and Waitara East, and Arahina and Pukepapa substations have sufficient transfer capacity to maintain category AA security. Other small towns and rural areas are supplied from single zone substations where there is either no interconnection or very limited interconnection to other zone substations.

6.9.3.10 Fault Levels and Equipment Ratings Analysis of fault levels on the network show that equipment and cable ratings are adequate.

6.9.3.11 Voltage Selection The subtransmission system is expected to be adequate for the planning period, and no subtransmission voltage other than 33 kV is foreseen during the planning period. 11 kV will remain the primary distribution voltage, but existing 6.6 kV will only be uprated where performance or economic advantages require it. Individual areas of the network may be constructed at or uprated to 22 kV if there is a performance or economic advantage.

6.9.4 Analysis Notes and Consideration of Alternatives A long term development plan has been prepared for the Powerco networks. This will lead to optimum use of existing assets and minimise the purchase of new equipment. Work completed so far indicates that the network will meet planning criteria for the planning period.

6.9.5 Zone Substation Configurations And Capacities – Development Summary Powerco's load forecast and maximum demand load indicates that the present zone substations are adequate except for the following areas. These are: · The possibility of replacing the Carrington GXP 11 kV bus with a Powerco zone substation is being considered. · Bell Block substation was planned to have its transformers upgraded to 16/24 MVA units. This may not now be needed, due to a significant decrease in load requirements by MCK Metals. · Keith St transformers were to be upgraded by installing the units to be removed from Bell Block. However, as Bell Block may now not need to be upgraded, new units may be purchased for Keith St instead. · Whareroa zone substation's present location within the premises of the Fonterra Dairy Plant is unsatisfactory because of access problems and contamination. One option is to relocate it nearby, on a more suitable site. · Turitea substation will be upgraded with the two 12.5/17 MVA transformers removed from Feilding. · Mangamutu substation will be upgraded with the two 7.5 MVA transformers now at Keith St. · A new zone substation is planned at Mosston, in Wanganui, to accommodate the growth of industrial load in the Castlecliff - Mosston area. · Peat St zone substation has provision for indoor 33 kV switchgear and a second 33/11 kV transformer. These will be installed during the planning period.

There are also several areas where reinforcements are an option, but consideration is being given to obtaining a mobile substation as an alternative solution. These are: · Beach Rd substation requires a second transformer in order to adequately supply large consumers under fault conditions. · Kai Iwi substation requires a second transformer in order to adequately supply a large and strategically critical consumer under fault conditions.

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· Manaia substation requires a second transformer in order to adequately supply large consumers under fault conditions. · A new rural zone substation is planned for Mataroa, adjacent to Mataroa GXP, to supply the local area, to reduce the load on Taihape zone substation and to provide an 11 kV backstop to Taihape or Waiouru in the event of a subtransmission fault. · A bi-directional 22 kV voltage regulator is required between Arahina and Rata to enable each to support the other under fault conditions. · A transformer upgrade will be required at Wanganui East substation in 2005. · Second transformers will be required at Te Ore Ore and Featherston substations in 2006.

All substations are capable of supplying the present load, however some have reached or are exceeding their class capacity. Presently, except for the substations listed above, all load can be supplied, although the desired security of supply may not be met, and voltage levels may be marginal in a few locations.

6.9.6 Summary of Subtransmission System Development Table 20: List of Subtransmission Development Work Year Site Proposed Work 2003 Kai Iwi Second transformer and switchgear extension * 2003 Beach Rd Second transformer and switchgear extension ** 2003 Mataroa (Taihape rural district) New zone substation * 2003 Manaia Upgrade Transformer 2004 Keith St Upgrade Transformers 2004 Mangamutu Upgrade Transformers 2004 Mosston Rd - Wanganui New zone substation (Mosston Sub) 2004 Bell Block New Transformers (depending on MCK Metals load) 2005 Waiwhakaiho area New zone substation 2005 Carrington New zone substation 2005 Linton – Main St New 33 kV cable 2005 Kelvin Grove New 11kV incoming cables 2005 Castlecliff Indoor 33kV switchgear 2006 Main St Install 33kV cabling 2006 Roberts Rd - Wanganui East New 33 kV link 2008 Turitea Install 33kV feeder ex Linton GXP 2008 Peat St Sub - Wanganui Indoor 33kV switchgear 2009 Peat St Substation Install second transformer *

Notes: * Could be replaced by mobile substation deployment ** Could be reduced in scale by mobile substation deployment

6.9.7 SCADA and Communication Network Development The SCADA system used until 2002 was comprised of five separate SCADA systems covering the Taranaki, Egmont, Wanganui, Manawatu and Wairarapa networks. A project to integrate these five systems into one system and a single operating standard is currently underway and is expected to be completed by August 2002. The SCADA integration project includes an upgrade to Powerco’s WAN facilities.

The master station terminals for the integrated system are installed at Powerco’s Network Control Centre. The SCADA system hubs that interconnect to the master system via Powerco’s WAN are located at New Plymouth, Hawera, Wanganui, Palmerston North and Masterton.

The SCADA master station facilities include load control, which provides automatic control of peak demands and tariff switching signals, if required, to the various networks.

A number of zone-substation sites do not have any SCADA facility or a very limited one. Powerco will continue upgrading existing substation installations and installing SCADA at substations where there is none.

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A SCADA development program has been formulated which includes further upgrading of the Master Station at the Network Control Centre to “Open Architecture” systems wherever possible to ensure flexibility in technology.

The present communication system does not have the capacity to enable Powerco to take full advantage of the amount of data now available from modern protection and monitoring equipment, so consideration is being given to upgrading the communications to zone substations as part of the SCADA development program.

Table 21: Communication System Development Year Substation Development 2002 – 2004 SCADA System Review/Upgrade comms. – SCADA Master to Hubs 2002 – 2006 Zone subs. (All regions) Review/Upgrade comms. – SCADA Hubs to Sub RTU’s 2002 – 2006 Zone subs. (All regions) Review/Upgrade comms. – To facilitate interrogation of modern relays. 2002 - 2004 Zone subs. (All regions) Install time-sync facilities to substations with modern protection relay equipment.

Table 22: SCADA and Automation Development Year Substation Development 2002 - 2005 All regions Line fault locators and RTU’s /Comms 2002 - 2005 All regions Distribution switches remote control existing key switching points 2002 - 2005 All regions Line circuit breaker upgrades 2002 - 2005 All regions Line circuit breakers, install SCADA control to key line CB’s 2002 - 2005 All regions Upgrade zone sub RTU modules – SCADA development 2002 - 2005 All regions Review/Upgrade load control facilities 2002 - 2003 Powerco Integrate the multiple SCADA master stations into a single master station facility. 2004 - 2005 Powerco Upgrade SCADA master station to include open architecture and associated technology enhancements – SCADA development 2002-2003 Kempton (Wairarapa) Install SCADA 2002-2003 Clareville (Wairarapa) Install SCADA 2002-2003 Norfolk (Wairarapa) install SCADA 2002-2003 Chapel Wairarapa) Install SCADA 2002-2003 Akura (Wairarapa) Install SCADA 2002-2003 Featherston (Wairarapa) Install SCADA 2002-2003 Gladstone (Wairarapa) Install SCADA 2002-2003 Wanganui East (Wanganui) Install SCADA 2002-2003 Kaiiwi (Wanganui) Install SCADA 2002-2003 Rata (Wanganui) Install SCADA 2002-2003 Waiouru (Wanganui) Install SCADA 2003-2004 Taihape (Wanganui) Install SCADA 2003-2004 Roberts Ave (Wanganui) Install SCADA 2003-2004 Wanganui East (Wanganui) Install SCADA

6.10 Distribution System Development (Medium Term Development Plan)

6.10.1 Introduction A medium term development plan is under preparation. It will deal with the distribution voltage and low voltage distribution system, from the zone substation through to the consumer point of supply.

The analysis and preparation of the development plan focuses on the following key objectives: · Assessment of the asset management drivers and performance targets.

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· Performance assessment of the present system · Review of network improvement recommendations · Maintenance of appropriate levels of security of supply and reliability of supply · Optimal development of the distribution system to meet consumer service objectives

6.10.2 Planning Period The planning period used for the medium term plan is two to five years, depending on the nature of the activity.

6.10.3 Assessment of Suitability of System For Present Needs And Analysis of Development Options

6.10.3.1 General Generally, the distribution network is well suited to its purpose. Normal peak loads can be supplied, and there is provision for backup during feeder faults. The ability to provide backup supply in the event of zone substation faults has been taken into account when considering zone substation expenditure.

6.10.3.2 Installed Capacity and Fault Rating No developments are required due to insufficient distribution feeder capacity during the planning period except for those associated with new zone substations. However some movement in the open-points is expected, to better spread the load to meet load growth at the end of the planning period. These open points are being reviewed as part of the medium term development plan preparation.

Some feeder alterations are required to provide backup supply in the event of zone substation faults.

It is expected that fault duties will be adequate on the 11kV distribution system until at least the end of the planning period.

6.10.3.3 Line-Recloser and Sectionaliser Installation Line reclosers and sectionalisers are being progressively installed in appropriate positions on the network, to reduce the extent and duration of outages.

6.10.3.4 Distribution Transformer Utilisation Powerco has a policy of improving the utilisation of distribution transformers in the long-term by removing transformers from under-utilised sites and placing them in locations where the required capacity better matches the transformer rating, provided it is cost effective to do so. In general, an under utilised transformer is noted, and is moved when a more appropriate site is identified.

6.10.3.5 Underground Conversion Programme Powerco is committed to spending one million dollars a year on overhead to underground conversion in the Palmerston North area as a condition of the Centralpower - Electropower merger. Conversion in other areas will be carried out as funds are made available from electricity trusts or other sources.

6.10.3.6 Fault Locators The use of fault locators on the 11kV network will be expanded and feedback from the locators is being investigated.

6.11 Lifecycle Asset Plan (Maintenance and Renewal Plan)

6.11.1 Introduction This section of the asset management plan describes how each type of asset will be condition monitored, maintained and renewed. A maintenance plan has been prepared for each type of asset, however, for

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This section provides and overview of the maintenance methodology, asset management strategy (including renewal decision making) and asset renewal summary.

6.11.2 Maintenance Methodology

6.11.2.1 Determining Maintenance Strategy The objective of the maintenance planning process is to determine the most cost-effective method for reducing the risk associated with the asset in achieving the required level of service potential and management drivers for the network.

Risk management analysis is used to determine the type and effects of maintenance through: · Identifying all hazards that present a risk to the asset performing its intended function. · Conducting a failure mode and effects analysis (FMEA). In performing the FMEA, the maintenance that can be performed to reduce or eliminate the consequences of the failure is reviewed and the type of maintenance is selected. · Determining the cost of the maintenance, cost of failure and selecting maintenance type that provides a positive NPV return.

Powerco’s maintenance policy is based on effective maintenance involving balancing the cost of repairs and replacements against the consequences of failure. Premature or too frequent repairs and replacement unnecessarily increase maintenance costs, whilst repairs which are delayed too long can increase the risk of failure and generally increase the repair costs overall. Age based repairs and replacement provide a conservative maintenance approach and generally result in unnecessarily high maintenance costs due to premature replacements. Where maintenance is required it is best based on condition.

Powerco’s maintenance work comprises the following elements: · Routine inspections and condition monitoring · Routine servicing · Evaluation of inspection and condition monitoring results to determine any maintenance requirements (this may be performed in the field at the time of inspection/condition monitoring or later by engineering staff) · Evaluating faults to predict maintenance requirements · Performing maintenance repairs and refurbishment as a result of the above.

6.11.2.2 Inspection And Condition Monitoring Powerco has developed specific routine inspection requirements for each asset type. These requirements are based on a combination of manufacturer’s recommendations, industry practice and Powerco’s own experience. Powerco’s experience is based on asset duty, incidence of faults, and the operating environment.

Greater emphasis is being placed on non-invasive diagnostic testing wherever practical. This work involves the adoption of new technology through the chemical analysis of transformer and switch oil, the use of infrared cameras, ultra-sound discharge detection and other techniques, as they become available.

In all cases, the frequency of the inspection and condition monitoring is based on the “lead time to failure”. The “lead time to failure” (LTF) is the time between when the asset condition begins to deteriorate to a point when it can be detected and the point of failure. Routine inspection work is scheduled from the date of the last inspection to fall within the LTF.

Under Powerco’s defect and capital works partnership agreements (PAs), the service provider has a responsibility to report defects observed while in the field. This defect information may be used to initiate inspections or maintenance. Under the faults PA the service provider may be requested to perform a “line patrol” inspection during or immediately after a fault. This inspection is typically documented and can

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6.11.2.3 Routine Servicing Routine servicing is prescribed where condition-based monitoring is not practical or possible. The application of these techniques is based on a combination of manufacturer’s recommendations, industry practice and Powerco’s own experience. Routine servicing work is generally scheduled from the date of the last service.

6.11.2.4 Evaluation Of Condition Monitoring Results The results of inspection and condition monitoring are analysed by specialist service providers or by Powerco engineers. The type and extent of maintenance prescribed (or replacement) will be dependent on results.

6.11.2.5 Evaluation Of Faults and Monitoring Reliability (Reliability Driven Maintenance) In addition to routine servicing, Powerco undertakes Reliability Driven Maintenance and this is achieved using the following techniques: · Evaluation of the type of faults occurring in a particular area of the network or on a particular type of equipment can provide information on how to prevent the faults from occurring. Appropriate maintenance can then be applied to prevent or eliminate further faults. The type of maintenance prescribed will depend on the type of failure mode. The review of the types of faults typically occurs six-monthly over a two to three year window in order to determine trends. · Evaluation of individual feeder performance indices over a rolling two-year window. Condition monitoring work will be initiated on feeders with poor reliability. The type of condition monitoring and the resulting maintenance would be dependent on the nature of the unreliability.

6.11.2.6 Performing The Maintenance As a result of condition monitoring or fault analysis, maintenance may be required. The type of maintenance performed will depend on the results of the investigation and evaluation. Where the relationship between the condition monitoring and type of maintenance required is known this is described in the maintenance plans that follow.

Where the condition monitoring indicates that an asset needs replacement (or refurbishment) this is typically scheduled to co-ordinate with other planned work in the area.

6.11.2.7 Criteria for Asset Renewal General criteria for asset replacement have been defined. For simple assets this may be scheduled by age (i.e. expulsive fuses, surge arrestors), on failure or more commonly on condition or reliability assessment.

6.11.3 Scheduling Maintenance and Renewal Activities Applying the maintenance plans and renewal criteria to the available asset data derives the schedules for maintenance and renewal of the network assets.

The renewal of major assets has been scheduled given their expected useful lives in the first instance; however, this replacement may be deferred or brought forward depending on the actual condition of the asset. There are also a number of other factors that can influence the need for asset renewal and these are discussed for each general asset class in section 6.11.5 below.

Complete maintenance schedules for all assets are prepared, however, for the purposes of information disclosure the type of condition monitoring and maintenance has been extracted from the life-cycle plans and summarised by general asset category. The scheduling and execution of distribution system condition monitoring and maintenance is co-ordinated across the asset base to minimise cost and avoid duplication of travelling. The detailed maintenance schedules have not be included in this plan.

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6.11.4 Individual Asset Lifecycle Maintenance Plans Individual asset lifecycle maintenance plans have prepared for the following asset types: · 33/11kV power transformers · 33kV isolators · 33kV circuit breakers · 33kV Surge arrestors · 33kV protection relays · 33kV and 11kV busbars · 33kV subtransmission cables · 33kV instrument transformers · 33kV subtransmission lines · SCADA RTU outstations · SCADA master station · SCADA supply batteries and charging system · Zone substation supply batteries and charging system · Protection relays · Distribution voltage circuit breakers · Distribution voltage instrument transformers · Distribution voltage and 400V distribution lines · Distribution voltage regulators · Distribution voltage isolators · Distribution voltage surge arrestors · Distribution voltage expulsion fuses · Distribution voltage distribution cables · Distribution transformers · Distribution switchgear: ground mounted · Distribution voltage line reclosers · 400 V distribution boxes (pillars) · Earthing systems.

6.11.4.1 Overhead Line Maintenance Summary

· Visual inspection of pole, conductor, crossarm, insulators and ancillary equipment at regular intervals · Mechanical or ultra-sonic testing of wooden poles · Infrared scans and detailed inspections of fittings, from bucket truck · RF inspection of insulators · Scheduled replacement of crossarms · Scheduled replacement of surge arrestors · Vegetation management · Earth testing · Specific maintenance is carried out as a result of condition monitoring or reliability assessment

6.11.4.2 Underground Cable System Maintenance Summary

· Review of operating ratings to ensure that operating ratings are correct for various operating conditions. · Visual survey of sub-transmission cable routes for possible damage points · VLF AC insulation tests on XLPE sub-transmission cables · Oil pressure monitoring · DC Insulation resistance tests on PILC cables

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· Sheath-to-earth insulation resistance tests on sub-transmission cables · Visual, infrared and RF inspection of terminations, as applicable · Visual inspection of link and pillar boxes · Specific maintenance is carried out as a result of condition monitoring or reliability assessment.

6.11.4.3 Distribution Transformer Maintenance Summary

· Inspect transformer tank & general fittings · Oil testing (acidity, dielectric strength & moisture tests performed on transformers >100kVA at prescribed intervals unless the transformer is completely sealed.) · Check and change breathers · Earth testing · Specific maintenance is carried out as a result of condition monitoring or reliability assessment · The transformer will be refurbished if physical and economic criteria are met.

6.11.4.4 Distribution Switchgear Maintenance Summary

· Visual inspection · Operating tests & mechanism servicing · Review of recloser and sectionaliser protection settings · Clean & re-seal external surfaces on cast resin type switchgear · Partial discharge testing on ground mounted switchgear · Ultra-sonic checks for dry type cable termination deterioration in ground mounted switchgear · Close-in inspection, infrared scans, adjustment and lubrication of isolators · Earth testing · Oil condition testing · Specific maintenance is carried out as a result of condition monitoring or reliability assessment · The switchgear will be refurbished if physical and economic criteria are met.

6.11.4.5 Zone Substation Maintenance Summary (a) Power Transformers and Tapchanger · Visual inspection for mechanical deterioration and damage · Tapchanger contact & mechanism maintenance · Dehydrating breather maintenance · General operating tests and maintenance · Oil Tests (furans, dielectric strength, moisture, acidity) · Insulation resistance/polarisation tests · Insulation power factor test · Infra-red scans.

(b) Circuit Breakers and Switchboards · Visual inspection for mechanical wear, damage and serviceability · General operational tests and maintenance- monitor operational performance · Insulation power factor test · High voltage test · DC Insulation Test · Contact resistance test · Partial discharge condition monitoring · Fault & disturbance relay timing/pickup tests · Protection setting review to ensure that the equipment being protected will be adequately served by the relay settings

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· Protection setting verification on-site · Protection system primary injection and secondary injection tests.

(c) Inspection and testing is also conducted on ancillary items at zone substations, including: · Instrument transformers · Isolators · Buswork & surge arrestors · Batteries and charger · Buildings, fences and enclosures · SCADA I/O integrity testing between input and master-station · Communication system · Earthing system. · LVAC supply

6.11.5 Asset Renewal Plans The asset renewal plans have been presented in summary in the following graphs. The graphs show forecast renewal expenditure for the next 15 years given the expected economic life based broadly on asset age. The graphs indicate a rolling 5-year average and a 15 year average for comparative purposes.

The renewal plans have been summarised by the general asset categories and commentary has been provided where necessary.

$25,000 Overage Replacement Cost Replacement Cost 15 Year Average Replacement Cost $20,000 5 year moving average Replacement Cost

$15,000

$10,000 Replacement Cost ($000) $5,000

$0 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Year of Renewal Figure 14: Total Infrastructure Asset Replacement Profile

This graph shows that because of rapid network development in the 1960s and 1970s, resulting in much equipment being installed around the same time, asset replacement costs are set to increase steadily between 2007 and 2017. Actual replacements will require staging to ensure that an abnormally large replacement cost is not programmed for any one year.

The ability to complete abnormally large renewal programs in a single year will be constrained by the availability of local resources. Additional resources can be obtained from the national market, but this would be at a higher cost.

The spread of over-age equipment is described under the asset category graphs (for those asset categories having over-age assets). In brief, over-age zone substation assets are spread evenly over the next ten years, and other over-age assets are spread over the next four years in the ratio 40%, 30%, 20%, 10%. The actual budgeting for renewal work in the upcoming (near term) years will reflect the actual condition of the assets given the most recent inspection and testing information. However, for the purpose of long term renewal planning spreading the over-age assets in the manner stated above is acceptable.

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6.11.5.1 Overhead Line Renewal Plan

$25,000

Overage Replacement Cost OH Line Replacement Costs $20,000 Average of 15 years OH Line Replacement Costs 5 yr moving Average Replacement Cost

$15,000

$10,000

Replacement Cost ($000) $5,000

$0 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Year of Renewal

Figure 15: Overhead Line Replacement Profile

This graph shows the actual recorded data on pole ages from GIS. However, when this data was collected many pole ages were not identifiable and an approximate age (based on the pole condition) was assigned. For poles with reasonable remaining life the condition vs age relationship was not easily determined. Hence, the renewal forecasts beyond 5 years must be considered as estimates only. Naturally, as the renewal date approaches a reassessment of expected renewal date will be made given the current condition information.

The forecast overhead line renewal expenditure (refer to section 6.12) exceeds the above projected renewal based on the assessment of economic life using the age data. In the near term renewal has been forecast in advance of the usual economic life, and reasons for this include: · Asset replacement due to actual condition. That is, the assessed condition from the most recent condition monitoring indicates that the forecast economic life will not be achieved and replacement is required. The asset replacement for this reason may occur as either a scheduled renewal or an unplanned defect renewal, depending on the time between inspection and recommended renewal date. · Unplanned defect replacement as a result of third-party damage · Removal of overhead lines to create heavy haul routes · Route realignment for Transit and others utility owners · Overhead line to underground conversion · Polymer insulator installation in heavy pollution areas · Network reconfiguration to achieve operational flexibility, improved reliability or efficiency.

6.11.5.2 Underground Cable Renewal

$250

UG Cable Replacement Cost

Overage Cable Replacement Cost $200 Average UG Cable Replacement Cost

5 Year Moving Average UG Cable Replacement Costs

$150

$100 Replacement Cost ($000) $50

$0 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Year of Renewal Figure 16: Underground Cable Replacement Profile

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There is $213,000 of over-age cable on the network, but then none due for replacement until 2015, and then only small amounts. For this reason, a meaningful graph cannot be presented. However, there are many instances where assets need to be replaced in advance of their usual economic life, including: · Asset replacement due to actual condition. That is, the assessed condition from the most recent condition monitoring indicates that the forecast economic life will not be achieved and replacement is required. The asset replacement for this reason may occur as either a scheduled renewal or an unplanned defect renewal, depending on the time between inspection and recommended renewal date. · Unplanned defect replacement as a result of third-party damage · Route realignment for Transit and others · Consumer requirements · Link box and underground tee replacement (safety and reliability) · Replacement due to repositioning of other assets (e.g.: distribution substations). · Network reconfiguration, to achieve operational flexibility, improved reliability or efficiency · Land subsidence, move cables to a secure area.

These items are planned in concept in the five year medium term distribution plan, and detailed planning does not usually occur until the preceding or current year in which the work is forecast. In particular, work to meet consumer requirements can sometimes be required at short notice. The expenditure forecast given in the later section reflects the factors mentioned above.

6.11.5.3 Distribution Transformer Renewal Plan

$3,000 Overage Tx Replacement Cost TX Replacement Cost $2,500 Average of 15 Years Tx Replacement Cost 5 Year Moving Average TX Replacement Cost

$2,000

$1,500

$1,000 Replacement Cost ($000)

$500

$0 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Year of Renewal Figure 17: Distribution Transformer Replacement Profile

An important indication from this graph is that distribution transformer replacement costs are set to increase around fourfold between 2003 and 2011, and then remain around that level. This is because of rapid network development in the past, resulting in much equipment being installed around the same time, and reaching replacement age at the same time.

There are some instances where distribution transformers are replaced in advance of their usual economic life. Examples of this from the current Powerco works plan include: · Asset replacement due to actual condition. That is, the assessed condition from the most recent condition monitoring indicates that the forecast economic life will not be achieved and replacement is required. The asset replacement for this reason may occur as either a scheduled renewal or an unplanned defect renewal, depending on the time between inspection and recommended renewal date. · Unplanned defect repairs as a result of third-party damage · Overhead transformer to pad mount (earthquake strength) · Overhead line to underground conversions · Severe corrosion in harsh coastal environments.

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The expenditure forecast given in the later section reflects the factors mentioned above.

6.11.5.4 Switchgear Renewal Plan

$9,000 Overage Switch Replacement Cost $8,000 HV Switch Replacement Costs Average of 18 years HV Switch Replacement Costs $7,000 5 year moving average Replacement Cost $6,000

$5,000

$4,000

$3,000

$2,000 Replacement Costs ($000)

$1,000

$0 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Year of Renewal

Figure 18: Switchgear Replacement Profile

An important indication from this graph is that there will be few switchgear replacements until 2006, but a large increase is likely from 2012 to 2016. As for other assets, this is because of rapid network development in the past resulting in much equipment being installed around the same time and reaching replacement age at the same time.

There is no over-age switchgear on the network, but switchgear sometimes needs to be replaced before the end of its economic life. Examples include: · Asset replacement due to actual condition. That is, the assessed condition from the most recent condition monitoring indicates that the forecast economic life will not be achieved and replacement is required. The asset replacement for this reason may occur as either a scheduled renewal or an unplanned defect renewal, depending on the time between inspection and recommended renewal date. · Unplanned defect repairs as a result of third-party damage · Network reconfiguration to achieve operational flexibility, improved reliability or efficiency · Replacement to remove safety hazards associated with the equipment.

Significant 11kV switchgear replacement work due to operational constraint and safety issues has been planned for 2003 and 2004. This work involves the planned replacement of live front LV switchgear, Yorkshire SoHi circuit breakers and ABB series 1 switchgear.

The expenditure forecast given in the later section reflects the factors mentioned above.

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6.11.5.5 Zone Substation Renewal Plan

$7,000

Overage Replacement Cost Substation Replacement Cost $6,000 5 year moving average substation Replacement Cost Average 15 years of substaion Replacement Cost

$5,000

$4,000

$3,000

$2,000 Replacement Cost ($000)

$1,000

$0 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Year of Renewal Figure 19: Zone Substation Replacement Profile

Zone substation equipment undergoes regular condition monitoring, and is replaced when its condition indicates that it should be. The graph indicates that there are two periods when replacement requirements will tend to be heavier than average.

There is some over-age zone substation equipment on the network, but changes in asset average age make comparison with last year inappropriate. The over-age asset replacement cost has been spread evenly over the next ten years, but due to its condition, there is no over-age equipment currently programmed for replacement in that time.

Assets sometimes need to be replaced before their rated life is over. Reasons for this include: · Asset replacement due to actual condition. That is, the assessed condition from the most recent condition monitoring indicates that the forecast economic life will not be achieved and replacement is required. The asset replacement for this reason may occur as either a scheduled renewal or an unplanned defect renewal, depending on the time between inspection and recommended renewal date. · Reliability issues, including spares and ability to service · Replacement due to operational constraint or safety issues · Insulator / structure replacement in heavy pollution areas · Replace / reposition zone substation due to load changes · Protection discrimination and control issues. Replacing equipment no longer capable of required discrimination · Environmental compliance issues.

For the zone substation assets the major upcoming renewal work is given in the tables below:

Table 23.1: List of Major Subtransmission Renewal Work - Taranaki Year Site Proposed Work 2003 Opunake 33 kV network Protection upgrade 2005 Cambria Replace 11 kV switchboard 2005 Manaia Replace 11 kV switchboard 2006 Kapuni Replace 11 kV switchboard 2008 Livingstone Replace 11 kV Switchboard

Table 23.2: List of Major Subtransmission Renewal Work - Wanganui Year Site Proposed Work 2003 Taihape Sub Substation rebuild

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Table 23.3: List of Major Subtransmission Renewal Work - Manawatu Year Site Proposed Work 2005 Bunnythorpe Replace 33kV circuit breakers 2006 Parkville Replace 11kV circuit breakers 2008 Kimbolton Replace 11kV circuit breakers 2010 Kairanga Replace transformers 2010 Feilding Replace 33kV circuit breakers .

Table 23.4: List of Major Subtransmission Renewal - Wairarapa Year Site Proposed Work 2006 Clareville Zone Transformers refurbish 2007 Awatoitoi Zone Transformer refurbish 2010 Tinui Replace or refurbish Voltage Regulators

The expenditure forecast given in the later section reflects the specific renewal projects and general renewal factors mentioned above.

6.12 Development, Renewal and Maintenance Expenditure Forecasts

6.12.1 Introduction The network expenditure forecasts describe the development, renewal and maintenance work required to: · Maintain the level of service performance for the assets · Develop the assets to meet the new and future load growth · Improve and enhance the service performance where the service standards are not being met.

The expenditure has been categorised into three categories: · Development (includes enhancement): Capital expenditure on new assets, or expenditure that materially changes the service potential (and performance) of the existing assets · Renewal: Capital expenditure on the replacement of existing assets that maintains the original level of service performance and extends the economic life of the system (that is, replacement of like with like) · Operating and maintenance: Operational expenditure that is required to operate or maintain the assets to achieve its original design economic life and service potential.

In the summary table the Asset & Network Management expenditure forecasts have also been included. This expenditure relates to the asset management and network control centre costs. These costs are a significant direct cost of operating the network.

In all cases, the expenditure forecasts for 2003 and 2004 have been based on detailed planning and assessment of the assets. The forecasts in the mid to later years have been set given the general application of the planning criteria and load growth projections to the network, and broad projections of asset condition based renewal and maintenance needs.

6.12.2 Expenditure Forecasts The asset management expenditure forecasts are given in the tables below. The forecasts are separated by the classes of expenditure and the asset type.

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Table 24: Expenditure Summary Forecast Expenditure Class 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Capital 18,729 20,407 21,504 22,205 23,009 23,619 24,332 25,251 25,972 26,491 Operation & Maintenance 14,085 14,226 14,368 14,512 14,657 14,803 14,952 15,101 15,252 15,405 Sub Total 32,814 34,633 35,872 36,717 37,666 38,422 39,284 40,352 41,224 41,896 Asset & Network Management 7,482 7,332 7,369 7,406 7,443 7,480 7,518 7,555 7,593 7,631 Total 40,296 41,965 43,241 44,123 45,109 45,903 46,801 47,907 48,817 49,527

Table 25: Total Expenditure Forecast (excluding Asset & Network Management) Asset Class 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Overhead Lines 11,998 13,479 13,685 13,793 13,901 14,011 14,122 14,235 14,348 14,550 U/G Cables 4,568 5,396 5,466 5,536 5,608 5,682 5,757 5,833 5,910 6,018 Dist. Switchgear 4,335 3,697 4,327 4,658 4,989 5,221 5,454 5,687 5,821 5,927 Dist. Transformers 5,065 5,055 5,109 5,165 5,221 5,379 5,637 6,098 6,458 6,568 Zone Sub. Equip. 6,848 7,006 7,285 7,566 7,946 8,129 8,314 8,500 8,687 8,834 Total 32,814 34,633 35,872 36,717 37,666 38,422 39,284 40,352 41,224 41,896

Table 26: Development Expenditure Forecast Asset Class 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Overhead Lines 1,148 1,308 1,334 1,361 1,388 1,416 1,444 1,473 1,502 1,532 U/G Cables 2,628 2,993 3,053 3,114 3,176 3,240 3,305 3,371 3,438 3,507 Dist. Switchgear 922 1,050 1,071 1,092 1,114 1,136 1,159 1,182 1,206 1,230 Dist. Transformers 1,600 1,823 1,859 1,896 1,934 1,973 2,012 2,053 2,094 2,136 Zone Sub. Equip. 2,355 2,683 2,737 2,792 2,847 2,904 2,962 3,022 3,082 3,144 Total 8,653 9,857 10,054 10,255 10,459 10,669 10,882 11,101 11,322 11,548

Table 27: Renewal Expenditure Forecast Asset Class 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Overhead Lines 2,957 4,200 4,300 4,300 4,300 4,300 4,300 4,300 4,300 4,386 U/G Cables 997 1,450 1,450 1,450 1,450 1,450 1,450 1,450 1,450 1,479 Dist. Switchgear 2,476 1,700 2,300 2,600 2,900 3,100 3,300 3,500 3,600 3,672 Dist. Transformers 1,651 1,400 1,400 1,400 1,400 1,500 1,700 2,100 2,400 2,448 Zone Sub. Equip. 1,995 1,800 2,000 2,200 2,500 2,600 2,700 2,800 2,900 2,958 Total 10,076 10,550 11,450 11,950 12,550 12,950 13,450 14,150 14,650 14,943

Table 28: Operating & Maintenance Expenditure Forecast Asset Class 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Overhead Lines 7,892 7,971 8,051 8,132 8,213 8,295 8,378 8,462 8,546 8,632 U/G Cables 944 953 963 972 982 992 1,002 1,012 1,022 1,032 Dist. Switchgear 937 947 956 966 975 985 995 1,005 1,015 1,025 Dist. Transformers 1,814 1,832 1,850 1,869 1,887 1,906 1,925 1,945 1,964 1,984 Zone Sub. Equip. 2,498 2,523 2,548 2,574 2,599 2,625 2,652 2,678 2,705 2,732 Total 14,085 14,226 14,368 14,512 14,657 14,803 14,952 15,101 15,252 15,405

6.12.3 Development Expenditure Forecast Development expenditure relates to development or enhancement of the network. The need to undertake development work is based on: · Growth in network load requiring an increase in network capacity · System security (and reliability) are below the standard · Expansion of the network to connect new consumers

6.12.4 Renewal Expenditure Forecast Renewal expenditure generally relates to the replacement of existing assets where these assets have been identified as being at the end of their economic life, based on their assessed condition. As the asset

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The forecast renewal expenditure for some asset types exceeds projected renewal expenditure based on original economic life and age. In many instances assets need to be replaced in advance of their original economic life and examples of this include: · The original economic life of the asset not being accurate due to the asset design, material selection and environmental conditions. · Network reconfiguration to achieve operational flexibility, improved reliability or efficiency. · Unplanned defect repairs, including third-party damage · Line/cable route realignment as a result of third-party requests · Overhead line to underground conversion · Replacement due to operational constraint or safety issues – Examples include live front LV Switchgear, ABB Series 1 and SoHi switchgear replacement projects. · Replace / reposition zone substation due to large consumer requirement change. · Protection discrimination and control issues. Replacing equipment no longer capable of required discrimination. · Environmental compliance issues.

6.12.5 Operating and Maintenance Expenditure Forecast The operating and maintenance expenditure forecast has been set based on the asset maintenance plans developed using the maintenance strategy and Powerco’s present operating practices. In general terms maintenance is required to maintain the asset’s service performance or is necessary for the assets to achieve their intended service potential.

Powerco’s operating and maintenance work comprises the following: a) Routine condition monitoring b) Routine servicing c) Evaluation of inspection and condition monitoring results to determine any maintenance requirements d) Evaluating faults to predict condition monitoring and maintenance requirements e) Performing maintenance repairs and refurbishment as a result of (c) and (d) above f) Fault repair g) Network operating.

6.13 Outsourcing of Development, Renewal and Maintenance Activities

6.13.1 Introduction Powerco (Asset Management Group) outsources all development, renewal and maintenance activities under the guidance of its outsourcing policy. The purpose of the network construction and maintenance outsourcing policy is to provide long term direction for the procurement of services for the development, renewal and maintenance of the electricity (and gas networks).

6.13.2 Powerco Outsourcing Policy Overview The outsourcing policy applies to the provision of all development, renewal and maintenance work (“Network Work”) on assets that are managed by the Powerco Asset Management group.

Network Work includes detailed design, construction, commissioning and preparation of as-built reports.

The principles of the Network Work outsourcing policy are to: (a) Deliver the required work on the Powerco Networks in a timely and efficient manner (b) Deliver sustainable improvement in the cost and quality of the Network Work

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(c) Fairly allocate the risk between Powerco and the Contractor (d) Maintain acceptable levels of safety performance by Contractors

To deliver on the outsourcing principles Powerco Asset Management shall create, maintain and utilise a competitive market to deliver superior performance in terms of cost, quality and safety in the provision of development, renewal and maintenance services on the electricity (and gas networks) where the utilisation of such a market will deliver long term sustainable value to Powerco.

6.13.3 Summary of Partnership Agreements and Contracts One significant partnership agreement exists between the Powerco Asset Management Group and the Powerco Network Services Group. The scope of this partnership includes the following general work types: · All fault and defect repair · All zone substation maintenance · All major ground level distribution substations and HV Switchgear maintenance · Detailed design for general line construction · Selected construction, maintenance, inspection and condition monitoring work for the subtransmission and distribution system · Selected zone substation development work

The quantity of work “selected” and issued under the partnership agreement is set at a minimum level to support the quantity and location of resources to deliver fault and defect response services. The selection of work over-and-above this minimum level is set given the performance of the Network Services Group and the need to support the competitive external market.

Powerco issues a significant number of large and small contracts during each year. Typically the work is performed under either lump sum or measure and value contracts. The typical type of work outsourced in this manner includes: · Distribution system condition monitoring and maintenance · Vegetation management · Selected construction work for the subtransmission and distribution system · Selected zone substation development work

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7. Risk Management

7.1 Risk Management Charter Powerco has a Risk Management Charter detailing Powerco’s approach to risk management. Relevant excerpts from it are appended as Appendix 1.

7.2 Risk Management Plans Following the guidance of the Risk Management Charter, Powerco has developed a series of 12 high level Risk Management Plans, with one of these plans dedicated to network asset management. An overview of the risk management process, that is integral to developing and maintaining the risk management plan, is given below

7.3 Risk Management Process

7.3.1 Purpose The purpose of risk management is to manage risks that may prevent the infrastructure assets from meeting service potential targets or cause harm to people or financial loss to Powerco. “manage risks” may mean to reduce, eliminate, transfer or accept the risk.

7.3.2 Scope This risk management charter and plans shall be applied to the planning for development and maintenance of all infrastructure assets covered by the Powerco asset management plan.

7.3.3 Risk Management Procedure: Review of Maintenance Methodology This procedure shall be used to review maintenance methodologies:

1. Identify the hazards that present risk: · to the safety of employees and the general public · to the environment · of electricity supply interruptions

2. These could be caused by: · environmental conditions such as lightning, ice, floods, slips, land subsidence or earthquake · external factors such as vehicle collision, trees, vandalism, bird strikes, opossums, uncontrolled digging or vermin/grass in kiosks · equipment failure such as inherent design inadequacy, continuous overload deterioration, moisture ingress or corrosion · operational error such as incorrect protection settings or operating wrong equipment · substandard workmanship such as jointing, binding, cable laying or terminating

3. Conduct a failure mode and effects analysis (FMEA ) on each class of assets and general groups of assets (i.e. zone substations). For each failure mode review the maintenance that could be performed to prevent or reduce the consequences of the failure.

4. Estimate the effects of performing the maintenance in reducing the likelihood and repair time for the failure

5. Calculate the cost of the maintenance or action

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6. Calculate the cost of the failure where this relates to electricity supply interruptions or environmental damage

7. For safety related risk, determine the severity rating and probable frequency, and determine what actions are required to reduce or eliminate the likelihood of the risk eventuating.

8. During the review consideration shall be given to the other asset management drivers to ensure that there are not any conflicts with the maintenance methodologies. Any conflicts that do exist should be resolved by reviewing all drivers.

9. Select the maintenance activities that · provide positive NPV, and; · those actions required from a health and safety standpoint, and; · that do not conflict with the other asset management drivers.

Note: In performing this activity the results of the existing maintenance practices should be reviewed. Feedback from the field that occurs during the execution of the maintenance may contain valuable information on the effectiveness or otherwise of the maintenance activity.

7.3.4 Risk Management Procedure: Review of Development Planning Criteria This procedure shall be used to check performance against planning criteria:

1. Select the planning criteria that determine appropriate equipment reliabilities, failure frequencies and repair times from company or industry statistics or from the FMEA for the asset type. Assume appropriate maintenance practices have been applied.

2. Where the planning criteria relates to reliability simulate the network configuration, given by the planning criteria, under normal conditions to determine the SAIFI, CAIDI and SAIDI. The planning criteria shall be accepted if the simulation results (the SAIFI, CAIDI and SAIDI) are within the feeder performance criteria or zone substation performance criteria.

3. Perform risk assessment using Powerco's prioritisation model. Identify all risks that could cause a crisis. How does the system handle the risk occurring? How can the system better handle the risk occurring? Consider all other asset management drivers when reviewing options to ensure that criteria are met and there is no conflict with other asset management drivers.

4. Check the performance outcomes against the planning criteria. If planning criteria fail to meet the performance criteria then the planning criteria will be amended. The other asset management drivers shall be considered when changing the planning criteria.

7.3.5 Risk Management Procedure: Project Prioritisation Powerco has developed a prioritisation model which is used to determine the risks involved in a situation and the degree of improvement offered by a project. This enables projects to be prioritised to ensure the greatest risk reduction is achieved with the available resources. The model considers safety, shareholder value, environmental considerations, liability issues and operations and maintenance advantages. The Summary and Scoring Method of the model are given in the Figures 26 and 27.

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JOB TITLE: Cost: ASSET NUMBER: Prepared By: Date: SUMMARY OF PRIORITY RATINGS Filename:

CATEGORY PRIORITY Project Description RATING

SAFETY ISSUES SHAREHOLDER VALUE NETWORK RELIABILITY ENVIRONMENT ISSUES POWER QUALITY DELIVERED DAMAGES LIABILITY OPERATIONS & MAINTENANCE

a exceptionally high value b high value or importance. c worth doing. d with regard to this factor - very small worth. e with regard to this factor - of no benefit. SCORE: f with regard to this factor - makes things worse.

Figure 20: Prioritisation Criteria Summary

JOB PRIORITY ASSESSMENT -A COMBINED SCORE

JOB TITLE: Cost: $0 Prepared By: 0 Date: 0-Jan-00 Filename: 0

Analysis Rating Factor Importance a 10 SAFETY ISSUES 10 b 5 SHAREHOLDER VALUE 7 c 2 NETWORK RELIABILITY 7 d 1 ENVIRONMENT ISSUES 7 e 0 POWER QUALITY DELIVERED 5 f -1 DAMAGES LIABILITY 5 OPERATIONS & MAINTENANCE 5

Analysis Rating Importance Result SAFETY ISSUES 10 0.00 SHAREHOLDER VALUE 7 0.00 NETWORK RELIABILITY 7 0.00 ENVIRONMENT ISSUES 7 0.00 POWER QUALITY DELIVERED 5 0.00 DAMAGES LIABILITY 5 0.00 OPERATIONS & MAINTENANCE 5 0.00 0

Figure 21: Prioritisation Scoring

7.3.6 Summary of Contingency Plans and Emergency Response Systems Details of emergency response criteria are contained in Powerco’s Electricity Supply Continuity Plan, which is currently undergoing significant review and is being based on the previously prepared Powerco and CentralPower disaster recovery documents. This is scheduled for completion in August 2002. This

Powerco Information Disclosure Asset Management Plan Electricity Network 2003 – 2012 Section Subject Date of Issue Page 7 Risk Management 30/06/02 73 plan deals with the Readiness, Response and Recovery aspects of network continuity management. The reduction of risk is handled under this Powerco Asset Management Plan and associated processes. The plan outlines Powerco’s policy for dealing with three identified levels of crisis.

Table 29: Levels of Crisis Crisis Level Type of Crisis Typical % of Load Affected in Any Region

1 Major equipment failure Between 10% and 20% or when the Duty Operational Overload Engineer calls out additional assistance Civil Unrest 2 Volcanic eruption Between 20% and 40% storm/cyclone flood 3 Major disruptive earthquake Greater than 40%

Level one is dealt with normal rostered staff plus additional staff as required. Level two and Level three may include involvement in a Civil Defence Emergency with overall control passing to the Regional Civil Defence Co-ordinator.

The Electricity Supply Continuity Plan is prescriptive in nature and sets out the composition, authority, responsibilities and the reporting structure for Crisis Management teams and resource allocation. Individual risks are not identified as procedures are designed to ensure that the support structure appropriate to the crisis level is mobilised.

Network Services Staff or contractors carry out all work on Powerco’s network. The Service Level Agreements and contracts signed with these suppliers require that an adequate field resource available to handle emergency situations at all times.

7.4 Conclusions from Risk Analysis The integration of risk management into the planning process during 2002 has led to a number of results. These are: · The application of the prioritisation model to all proposed development projects. This is an essential element of the Works Approval Memorandum or Sanction for Expenditure required before any development project is authorised to proceed. · An Audit of zone substations to determine accurate firm capacities. Discoveries during this audit have led to several substation elements being de-rated and substation loading guides programmed for production by August 2002. · Preparation of standards for zone substation and distribution feeder security levels, followed by a study of zone substations not meeting required security levels, determining upgrade requirements, and prioritising for upgrading. · Development of a formal procedure for preparing contingency plans for loss of supply to major or strategically important consumers. · Production of comprehensive substation operating manuals programmed for completion by July 2003. · A study of the worst performing 10% of distribution feeders has resulted in a programme to improve their performance by 60% during 2003.

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8. Performance Measurement and Review

8.1 Introduction This section presents a review of Powerco performance against target for 2002. This section discusses the factors that influenced the performance and compares these against the industry where a reasonable comparison can be made.

Detailed discussion of the performance measures and targets is not provided as this is covered in section 5 of the plan.

8.2 Review of Previous Plans

8.2.1 General Review Comments This plan is the result of the review of the Powerco Asset Management Plans issued on 28 June 2001 and 30 June 2000. Preparation of the asset management plan is an ongoing process throughout the year, but work intensifies between April and June, when final results are available. This year’s plan has improved on previous plans due to the ongoing information and data enhancement program that has resulted in additional data becoming accessible and existing data being more accurate. It has enabled Powerco to establish a more comprehensive set of performance targets for 2003, and to monitor performance against them more accurately.

8.2.2 Review Work In Progress Powerco has reviewed its long term development plan, covering subtransmission development for a 15 year period to 2017. Preparation of a medium term development plan covering distribution network development for a five year period to 2007 is in progress and is due for completion in September 2002.

8.3 Review of Service Performance Against Targets

8.3.1 System Reliability Performance Powerco’s overall system reliability performance as measured by SAIDI was below target, however the performance was in the good performing category when compared to the 2001 industry performance. In summary, the performance target was not achieved due to a number of factors: · The 2001 mid-winter storms experienced in the northern Manawatu, Taihape and South Taranaki regions. This single storm contributed to over 20 system SAIDI minutes (over 15% of the annual total). The storm was considered by locals as a one-in-thirty year event. · The higher than normal amount of lightning activity in the Taranaki region. 45 transformers were replaced as a result of lightning damage in the Wanganui & Taranaki regions. Lightning also affecting Carrington and Mataroa GXPs. · A number of protection related zone-substation outages to the Pascal St and Keith St substations in Palmerston North and to the Inglewood substation in Taranaki. · The performance five “rouge” feeders that experience ongoing poor reliability performance while the faults were located and repaired. · Higher than forecast level of work being performed “dead line” rather than “live line”. · A high number of third party interference, vehicles hitting poles and diggers hitting 11kV feeder cables.

The 2002 reliability performance is summarised in the table below:

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Table 30: Powerco Reliability Performance Summary Performance Measure Unit Powerco Actual Target 2002 Industry Industry 2002 Average 2001 Medium 2001 SAIDI (B+C) minutes per 130 100 175 131 customer SAIFI (B+C) interruptions per 2.2 1.9 2.4 2.1 customer CAIDI (B+C) minutes per 58 53 71 64 interruption

Note: The industry data was taken from the PricewaterhouseCoopers Electricity Lines Business 2001 Information Disclosure Compendium – March 2002.

Powerco’s reliability performance has been steadily improving over time and this is illustrated in figure 22 below. 2002 showed an increase in SAIDI compared with previous two years, however, the five-year trend remains positive.

Comparing Powerco’s reliability performance to the 2001 industry information shows that Powerco is in the good performing category. Figure 23 shows the recent reliability performance against network customer density and Powerco performs well in this area when considering that line companies with lower customer density tend to have higher SAIDI due to the fault rate being proportional to line length.

The 2003 SAIDI target of 98 will place Powerco in the good performer range should it be achieved and is appropriate given the present network configuration. Significant reliability based asset investment would be required to improve performance markedly from the present target.

Powerco SAIDI Performance 180 Linear (SAIDI) 160

140

120

100

80

60 SAIDI (class B&C) 40

20

- 1998 1999 2000 2001 2002 2003 Year (FYE) Figure 22: Powerco Reliability Performance Trend

Notes: The 2003 SAIDI stated in the above graph is the target for 2003.

SAIDI vs Customer Density 40

Powerco 2003 35 Powerco 2002

30 Powerco 2001

25

20

15 Customer Density (ICP/km) 10

5

0 0 50 100 150 200 250 300 350 400 450 500 550 600 SAIDI (classs B&C) Figure 23: Powerco SAIDI vs Customer Density based on 2001 Information Disclosure Data

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8.3.2 Regional Reliability Performance The reliability performance has been disaggregated by region in Table 31 below. This table provides details on the line fault rates which is a contributing measure to overall reliability.

The reliability (SAIDI class B+C) is poor in the Wanganui and Wairarapa regions when compared to other regions. For Wanganui this was due to the mid-winter storms. For Wairarapa, the lower performance was due to the large planned outages that occurred during the significant line reconstruction program taking place in the region.

The restoration times in the Wanganui and Wairarapa region were also longer than in other regions due to the geographic spread of the network and the location of the resources.

The fault rates were better than target in all regions other than Taranaki, which may been due in part to the level of lightning strikes that occurred in the region.

Table 31: Regional Reliability Performance Service Performance Measure Unit Powerco Actual 2002 Target Taranaki Wanganui Manawatu Wairarapa Total 2002 SAIDI (B+C) minutes per 118 149 113 171 130 100 customer SAIDI (All Classes) minutes per 128 264 118 173 160 customer SAIDI (Class A) minutes per 0 40 1 0 9 customer SAIDI (Class B) minutes per 33 26 32 82 38 25 customer SAIDI (Class C) minutes per 85 123 81 89 92 75 customer SAIDI (Class D) minutes per 10 75 4 2 21 customer SAIFI (B+C) interruptions per 2.3 1.8 2.7 1.5 2.2 1.9 customer SAIFI (All Classes) interruptions per 2.5 2.7 2.8 1.8 2.6 customer SAIFI (Class A) interruptions per 0.0 0.2 0.0 0.0 0.0 customer SAIFI (Class B) interruptions per 0.2 0.1 0.2 0.4 0.2 0.2 customer SAIFI (Class C) interruptions per 2.2 1.7 2.5 1.2 2.0 1.7 customer SAIFI (Class D) interruptions per 0.1 0.7 0.1 0.3 0.3 customer CAIDI (B+C) minutes per 50 82 41 113 58 53 interruption CAIDI (All Classes) minutes per 52 97 42 97 62 interruption CAIDI (Class A) minutes per 0 256 89 0 233 interruption CAIDI (Class B) minutes per 219 215 155 227 198 153 interruption CAIDI (Class C) minutes per 39 73 32 77 45 43 interruption CAIDI (Class D) minutes per 70 101 35 7 75 interruption Faults per 100km - O/H and U/G Number per 10.1 8.6 8.4 7.6 8.9 9.1 100km Faults per 100km - U/G Number per 3.0 1.8 5.2 2.2 3.9 5.0 100km Faults per 100km O/H Number per 10.4 8.8 8.8 7.7 9.1 9.4 100km

8.3.3 Distribution Feeder Class Reliability Performance Powerco has set feeder interruption duration index (FIDI) targets for each of its five feeder classes and all feeders have been assigned a feeder class commensurate with the customers connected. Measuring individual feeder performance provides a disaggregated measure of service performance that is more closely aligned to what the individual consumers’ experience.

The following graphs show the worst performing feeder in each class for 2002. The data has been used to track performance and initiate improvements in the performance of these feeders. To put the performance data into perspective, Powerco has 380 distribution feeders and 86% of these performed better than target. Hence, the vast majority of consumers received an electricity supply within targeted reliability.

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The performance of the feeders is consistent with the overall system reliability which was also over-target. A number of the poor-performing feeders identified below relate to the 2001 mid-winter storms experienced in the northern Manawatu, Taihape and South Taranaki regions. This single storm contributed to over 20 system SAIDI minutes (over 15% of the annual total).

For all the under-performing feeders identified below, the performance gap has been investigated and corrective and preventative actions undertaken to prevent future poor performance. Significant performance issues or events that caused the poor-performance have been commented on under each graph.

The following graphs show planned and unplanned FIDI for each security class. The horizontal orange line represents the FIDI target for the feeder class. Note that there are no under-performing class F5 feeders.

Worst Performing Feeders - Class F1 180 160 Planned FIDI 140 Unplanned FIDI 120

100 80

FIDI Minutes 60 40

20 0

MANAIA

MANGATOKI DAIRYFACT BELL BLOCK 3 BELL BLOCK 4 Feeder Name Figure 24.1: Worst Performing Feeders Class F1

Commentary: · Manaia: The effects of storm damage, lightning and Motor Vehicle Accidents contributed to the unplanned interruptions. SCADA communication problems lengthen the outage times and these have since been repaired. · DairyFact: The two faults that caused interruptions were a surge arrester failure and possum line contact. Remedial work included insulator changes and tree clearance from the line. · Mangatoki: Two significant interruptions were caused by vehicle hitting a pole and a digger hitting a feeder cable.

Worst Performing Feeders - Class F2 500 Planned FIDI 450 Unplanned FIDI 400

350

300

250

200 FIDI Minutes

150

100

50

0

LINTON HOPE ST MARTON OHAKEA MILSON NO 3 LINE PAHIATUA COLLEGE HEADS RD FAIRS RD POLSON ST MALDEN ST RANGITIKEI AOKAUTERE PASCAL ST 4 WEST QUAY BELL BLOCK PASCAL5 ST 11 WYNDHAM ST WAINGAWA RD ARMSTRONG ST GLOVER RD EAST WATERWORKS RD SOUTH RD CHAPEL

TAIHAPE TOWN NORTH Feeder Name Figure 24.2: Worst Performing Feeders Class F2

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Commentary: · Aokautere: The significant interruptions were caused by two separate cable faults caused by third- party damage and a customer felling trees into the line. On-line SCADA line monitored has been installed and SCADA controlled switchgear has been installed to allowed supply outages to be minimised. Further undergrounding of 11kV distribution feeder is planned for 2003. · Waterworks: Trees have been identified as the main cause for the outages. Tree trimming has been targeted in this area. · Pahiatua: One fault has caused the major loss in unplanned minutes. The planned component is due to reconstruction of overhead line. · Glover Rd East: The significant interruptions were caused by a lightning strike severed a conductor and a contractor cutting bamboo bringing down the 11kV line. · Pascal St 4: One fault caused by the failure of an item of distribution switchgear. No further work planned. · Pascal St 11: One fault due to digger hitting cable. No further work planned.

Worst Performing Feedes - Class F3 400 Planned FIDI Unplanned FIDI 350

300

250

200

FIDI Minutes 150

100

50

0

RAETIHI TAKARO PARK RD RUAPEHU NGATAWA WAVERLEY OXFORD ST ARGYLE ST CHURCH ST EKETAHUNA MOTUROA 3 MOTUROA 7 MOTUROA 9 WEST TOWN COLOGNE ST BELL BLOCK 2TAVERNER ST SOMERSET RD CARRINGTON 5 PEAT ST INLAND CLOTON RD SOUTH HUNTERVILLE 22KV ARAMOHO RIVERSIDE Feeder Name Figure 24.3: Worst Performing Feeders Class F3

Commentary: · Raetihi: A number of fault occurred on the feeder. Significant reconstruction has been initiated and is planned to be completed in 2003. · Takaro: One interruption due to a cable fault. No further work planned. · Cloton Rd South: Storm damage & lightning strikes were the main causes of interruptions. Remedial work completed. · Hunterville 22kV: Interruptions have been due to snow storm in August 2001 and a number of outages on the 11kV Ongo section. Reconstruction on the 11kV Ongo section is in progress and parts of the 22kV line section. Tree cutting is also on progress. · Cologne St: One significant interruption in poor weather conditions resulted in the feeder being left isolated overnight contributed to the high figures. Martinborough zone substation is programmed to have SCADA installed to provide faster response times. · Eketahuna : One interruption due to a vehicle hitting a transformer structure. · Waverley: Deterioration of conductors due to excessive wind & salt conditions resulted in several interruptions. 4.5 km of conductor, crossarms and insulators have been replaced. Line fusing has been installed to isolate tree interruptions from a pine plantation, while negotiations with owners over permanent clearance progresses. · West Town: Interruptions to the mainly urban feeder occurred in a small rural section of the feeder. Tree trimming has been targeted and a line recloser is planned to be fitted separating the urban and rural sections in 2003

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Worst Performing Feeders - Class F4 2500 Planned FIDI

Unplanned FIDI

2000

1500

1000 FIDI Minutes

500

0

PIHAMA IHURAUA PIRINOA MATAROA TAUWERU BURNSIDE HOROEKA CLIMIE RD TIRAUMEA PUKETIRO COONOOR LONGBUSH RANGIWAHIAPUNGAREHU MOAWHANGO STRATHMOREMANGAMAIREBROOKLANDS MANGAWEKA

MAIN RD MOTONUI SOUTH RD NGARIKI

WESTMERE GLADSTONE Feeder Name Figure 24.4: Worst Performing Feeders Class F4

Commentary: · Mataroa: Interruptions have been due to snow storm in August 2001. Reconstruction has been carried out. · Ihuraua: One Interruption has constituted the majority of the figures shown. No further work has been planned. · Westmere Gladstone One interruption in poor weather conditions resulted in the feeder being left out overnight have contributed to the high figures. · Coonoor: Major reconstruction work has been carried out due to poor feeder performance in 2001. Work has now been completed. · Strathmore: Storm damage and trees the main cause of interruptions. The planned outages relate to the replacement of an11kV structures and tree cutting.

The maximum FIDI for each feeder security class (F1 to F5) are given in Table 5, section 5.2.3 and these targets include upstream interruptions. The actual feeder FIDI has been captured on the graphs above so the FIDI targets have been adjusted down to reflect the percentages of interruptions caused by upstream equipment.

8.3.4 System Capacity Performance The network performed to the required level in terms of capacity. Any forecast capacity shortfalls have been dealt with under either the long or medium term plans, and projects have been scheduled where necessary.

In terms of capacity performance at an individual customer level, a normal number of capacity upgrades due to consumer load changes were undertaken during the year. In the rural area, a higher than normal number of capacity upgrades were undertaken due to many dairy farmers upgrading milking shed equipment. The increase in rural load is being monitored closely to ensure the high voltage system continues to provide the necessary performance.

8.3.5 System Quality Performance The network performed to the required level in terms of voltage and quality. A number of voltage complaints were received, however these were predominately causes due to the consumer or adjacent consumers increasing their load. These issues were dealt with in accordance with standard Powerco policy.

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A very small number of consumer property damage complaints were received as a result of voltage fluctuations. Powerco undertook investigations in all instances and the fluctuations were outside the reasonable control of a prudent network operator.

8.4 Review of Economic Efficiency Performance Against Targets

8.4.1 Asset Efficiency Performance Powerco’s asset efficiency performance is presented in table 32 below. A number of measures have been used to present the view on asset efficiency. Powerco’s performance has compared well against target.

Powerco’s ODRC/ICP of $2,390/ICP compares well against the industry average ODV/ICP of $2919/ICP. However, this comparison is of limited use as it considers depreciation and hence, those networks with a higher average asset age will perform better than those of newer construction.

Figure 25 presents a plot of asset efficiency (ODV/ICP) versus SAIDI using the 2001 disclosure information. In this comparison Powerco is in the good performing category.

Improvement to asset efficiency will occur over the long term.

Table 32: Asset Efficiency Performance Measures Performance Measure Unit Powerco Actual 2002 Target Taranaki Wanganui Manawatu Wairarapa Total 2002 Asset Efficiency (ODRC/ICP) (Note 1) $/ICP 2486 2123 2415 2507 2390 2400 Asset Efficiency (RC/ICP) (Note 2) $/ICP 4595 4443 4523 5435 4654 4800 Asset Efficiency (ODRC/MWh) (Note 3) $/MWh 175 185 170 219 180 180 Asset Efficiency (RC/MWh) (Note 4) $/MWh 323 388 318 474 351 360 Capital Efficiency (Note 5) % na na na na na 100 Change in Asset Service Potential (Note 6) % na na na na na >0

Notes: 1. Asset efficiency (ODRC/ICP) is the ratio of network optimised depreciated replacement cost over number of ICPs. 2. Asset efficiency (RC/ICP) is the ratio of replacement cost over number of ICPs. 3. Asset efficiency (ODRC/MWh) is the ratio of network optimised depreciated replacement cost over input network MWh. 4. Asset efficiency (RC/MWh) is the ratio of network replacement cost over input network MWh. 5. Capital efficiency is the annual network Capital Expenditure over the change in ODRC as a percentage. It will only be calculated when both start and end ODRC values are known. It excludes the reduction due to depreciation and any gain due to asset revaluation during the period. 6. Change in Asset Service Potential is the change in ODRC from year start to year end. It will only be calculated when both start and end ODRC values are known. It includes the reduction due to depreciation but excludes any gain due to asset revaluation during the period.

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Asset Efficiency vs SAIDI 7,000 Powerco 2003 Target

Powerco 2002 6,000 Powerco 2001

5,000

4,000

3,000 Asset Efficiency (ODV/ICP) 2,000

1,000

0 0 50 100 150 200 250 300 350 400 450 500 550 600 SAIDI Figure 25: Asset Efficiency vs SAIDI based on 2001 Information Disclosure Data

8.4.2 Asset Utilisation Performance Asset utilisation is a key driver of long term asset efficiency. Powerco performance was good when compared to the targets set.

The load factor and substation transformer utilisation were in the good performing range when compared to national and international benchmarks. The national average for load factor (from the 2001 information disclosure) was 63.5%.

The distribution transformer utilisation was slightly under the national average (from 2001 information disclosure) of 33.7%. It is typical for less dense networks to have a lower distribution transformer utilisation due to the high number of single consumer transformers in the rural areas.

Table 33: Asset Utilisation Performance Measures Performance Measure Unit Powerco Actual 2002 Target Taranaki Wanganui Manawatu Wairarapa Total 2002 Substation Transformer Utilisation (Note 1) % 60% 67% 52% 59% 58% 58% Distribution Transformer Utilisation by % 31% 29% 33% 25% 30% 30% supply MD (Note 2) Distribution Transformer Utilisation by % na na na na na 38% disaggregated feeder MD (Note 2) Load Factor (Note 3) % 67% 59% 59% 66% 64% 60% Feeder Capacity Utilisation (Note 4) % na na na na na 38% Line Losses (Note 5) % na Na na na na

Notes: 1. Zone substation transformer utilisation is the substation maximum demand over the total substation ONAN rating. 2. Distribution transformer utilisation is calculated for both aggregated and disagregated demand. Aggregated: Network kW MD over distribution transformer capacity. Disaggregated: Sum of disaggregated feeder MDs over distribution transformer capacity. 3. Load factor is the ratio of (System kWh)/(System MD kW * 365 * 24). 4. Feeder capacity utilisation is the disaggregated feeder MD over the total distribution feeder winter 6pm capacity. It cannot be calculated yet due to partial lack of data. 5. Line losses can not be calculated due to partial lack of data for electricity sold over the system.

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8.4.3 Cost Performance Powerco’s direct cost performance is presented in the table below. The actual performance for 2002 was close to target (0.7% variance).

Figure 26 presents a plot of direct costs versus SAIDI (using the 2001 information disclosure information). This analysis presents a view of the key cost and service component. Powerco is in the good performing category when compared to the industry where the industry average direct costs per km is $1,165/km (2001).

Table 34: Powerco’s Direct Cost Performance Measure Actual Performance Target 1998 1999 2000 2001 2002 2002 Direct Costs/km 1,113 796 976 1,152 998 991

Note: The direct costs include the network operating and maintenance, asset management group and network control centre costs.

Direct Cost per km vs SAIDI 3,000 Powerco 2002

Powerco 2001 2,500

2,000

1,500

1,000 Direct costs per km

500

0 0 50 100 150 200 250 300 350 400 450 500 550 600 SAIDI

Figure 26: Direct Costs vs SAIDI based on 2001 Information Disclosure Data

8.5 Review of Safety Performance Powerco Network Services Group or contractors perform all construction and maintenance work on Powerco’s network, and the health and safety programmes of all are monitored. In the 2002 year there were 6 accidents on the network resulting in 184 hours lost time.

8.6 Review of Environmental Performance During 2002 no significant environmental incidents occurred on Powerco’s network.

8.7 Review of Physical Performance Against Plan For the 2002 financial year, the physical progress of development, renewal and maintenance activities is summarised below: · The capital works program (development and renewal) was 94% completed. There was some deferment of lower priority work to the 2003 financial year. · The maintenance work program was 98% completed. A small amount of inspection and condition monitoring work was deferred to early 2003 (financial year). · No defect work discovered during condition monitoring or other activities was deferred to the extent that it presented a significant future risk. Most defect work was completed within three months of the defect being identified.

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With respect to major subtransmission and zone substation development and equipment replacement the progress against the 2002 plan is summarised below: · The installation of the 11kV switchboard at Main St substation was 85% at the financial year end and completion was achieved on 31 May 2002. · Investigation into the new Mataroa substation continued in 2002, however the project has been deferred while other options are investigated. · The connection of the Pascal St – Kairanga (Gillespies Line) subtransmission circuit was completed. However, final commissioning was not completed due to the review of the protection scheme being undertaken. · Investigation into the 33kV or 11kV connection between Bulls and Sanson substation has commenced. The project has not yet been finalised. · The installation of the second transformer at the Norfolk substation was 75% complete at the financial year end and completion is scheduled for July 2002. · Practical completion was achieved on Feilding substation upgrade project in early 2002. · Practical completion was achieved on the Inglewood substation upgrade project in early 2002. · The installation of a new SCADA masterstation and upgrade of communication between the master hubs and the master station was 50% at financial year end and completion is scheduled for July 2002. · The SCADA RTU upgrade projects continued in 2002 and most projects achieved practical completion in 2002. The program is continuing in 2003.

8.8 Review of Financial Progress Against Plan The financial progress against plan is summarised by asset category in table 35 and 36 below. Commentary on the variance between actual and budget is provided below.

Capital Expenditure: · Expenditure on overhead lines was greater than planned due to the level customer lead developments and the high number of reactive pole replacements. A significant proportion of the additional reactive expenditure occurred during the mid-winter 2001 storms. · Expenditure on underground cables was behind budget due to delays experienced in the Palmerston North city overhead to underground conversion program and due to a lower level of defect repairs being required. · The expenditure on distribution substations was higher than budget due to the high number of transformers damaged by lightning and level of customer lead developments. There was a significant number of transformer upgrades in the dairy sector. · A number of zone substation projects (Mataroa, Main Street and Norfolk) either did not progress or were behind original forecast, which contributed to the expenditure being behind budget.

Maintenance Expenditure: · Maintenance expenditure closely followed budget over most asset categories. Standardisation of maintenance regimes across the regions has resulted in some variances in expenditure over budget for switchgear and transformers.

Table 35: Capital Expenditure Summary Asset Type ($000) Capital Expenditure 2002 Actual Budget Variance Overhead Lines 6,292 5,384 -907 Underground Cables 3,576 4,294 717 Distribution and Subtransmission Switchgear 1,480 1,908 428 Distribution Transformers 3,884 2,921 -963 Zone Substation Assets 3,564 4,575 1,011 Total 18,796 19,082 286

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Table 36: Maintenance Expenditure Summary Asset Type ($000) Maintenance Expenditure 2002 Actual Budget Variance Overhead Lines 4,376 4,546 170 Underground Cables 615 585 -30 Distribution and Subtransmission Switchgear 1,171 955 -216 Distribution Transformers 774 1,068 294 Zone Substation Assets 1,517 1,418 -99 Total 8,453 8,572 120

Note: The 2002 maintenance expenditure budget differs from the forecast made in the previous AMP ($9.32M) due to the exclusion of voice and data communication, power, water and rates budget and costs being excluded from the above summary. The total budget including these costs was $9.3M.

8.9 Improvement Initiatives

8.9.1 Network Improvement Sub-process The purpose of the Network Improvement sub-process is to proactively monitor service quality issues and improve network service performance. The objective is to ensure the networks deliver the required performance and that substandard performance is addressed promptly and effectively.

The Network Improvement sub-process includes both reactive (short term) and proactive (long term) performance management elements, and provides important feedback to the planning process.

Currently network improvement activities are occurring, however the process is not formally implemented. The key gaps that need to be addressed are: the quality of information and the filtering-out of low value work. The timely solving of protection related issues by the Planning team is also required.

Although operational, the Network Improvement sub-process is under development and is due for completion and final implementation by August 2002.

8.9.2 Summary of Improvement Initiatives Undertaken in 2002 A number of improvement initiatives were undertaken in 2002, with many centred on improving the reliability of under-performing feeders. The improvement initiatives are summarised below: · Fusing of some spur lines · Review of protection settings · Removal of redundant air break switches · Replacement of older reclosers with modern automated reclosers · Installation of automated distribution switches · Review of the lightning protection standards and implementation of an upgrade program · Review of the protection scheme design and implementation for the numerical protection relays. Setting changes have been implemented in a number of areas · Installation of a 11kv voltage regulator on the Oroua Downs feeder supplying Himitangi beach township.

8.9.3 Future Improvement Strategies An examination of the performance against target shows that the area where targets are not being met is that of SAIFI, SAIDI and CAIDI. While some of this is weather dependant, caused by storms, there are two areas in which significant performance improvements can be made. These are: · Addressing those zone substations which are not currently offering the security class required by their size and class of load. This is a longer term strategy, stretching over several years, and its effect on SAIDI or SAIFI will depend on whether a critical fault occurs on one of these substations in any year. In particular, this will involve implementing security class AA+ for locations where AAA security is

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desirable but not economically or technically feasible. This will ensure that interruptions are limited to less than 15 seconds. This is currently implemented at only one substation. · Continued monitoring and management of the worst performing distribution feeders. Significant improvement in the performance of the worst performing 10% of feeders has been targeted for 2003. The installation of more on-line and off-line fault locators on the distribution network is planned for 2003. · A review of the location and availability of resources in the Wairarapa and Wangauni region to reduce the CAIDI in these two regions. The CAIDI (measure of the average length of an interruption) is significantly higher in these two regions than in Manawatu and Taranaki. · Continuation of the lightning arrestor implementation program in the Taranaki region. · Re-issuing “locate before you dig” brochures to civil contractors to minimise damage to cables.

The areas of faults per 100 km, asset efficiency, capital efficiency, asset utilisation and direct costs are on target, but improvement opportunities will be investigated in these area as part of the planning process..

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Appendix 1: Excerpts from Risk Management Charter

Background Powerco’s historical approach to risk management has been fragmented, in the form of ad hoc systems of risk control; for example hazard controls in the workplace and disaster recovery plans.

The Executive Management Team has identified the need for an efficient, effective and demonstrable Risk Management Process within Powerco, which forms an integral part of the company’s management process.

This document describes Powerco’s Risk Management Charter, which is consistent with and builds on the established principles of risk management as detailed in: - · Australian/New Zealand Standard – Risk Management (AS/NZS 4360:1999) · Standards Australia – A Basic Introduction to Risk Management (SAA HB142 – 1999) · Australian/New Zealand Standard – Guidelines for Managing Risk in the Australian and New Zealand Public Sector (SAA/NZS HB143:1999) · Risk Financing Guidelines (SAA HB141-1999)

This Charter is produced under the authority of the Audit Committee, which has endorsed the document for the approval of the Board.

This is a controlled document within the Powerco Quality Management System and any future updates will be in accordance with that system. Any enquires should be directed to the Corporate Risk Manager.

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Risk Management Policy The Chief Executive has issued a Risk Management Policy, as set out below, which has been endorsed by the Executive Management Team, who wish to emphasise that risk management is a critical aspect of the effective internal management of Powerco.

Powerco’s Risk Management Policy

The governance of Powerco lies with the Board and is defined in Powerco’s Corporate Governance Charter. The Executive Management Team has the responsibility and accountability for the representation, direction and business success of Powerco. This requires a management process, which includes a flow of information to and from the Chief Executive and the Board. All aspects of Powerco’s activities need to be included in this process, including exposure to risk, which is therefore a critical aspect in the effective discharge of management responsibilities.

The Board is accountable for risk within Powerco but delegates policy execution to the Executive Management Team. In order to ensure that risk management is recognised and treated as a core competency, Powerco has implemented a coordinated framework for the management of risk as detailed in the Risk Management Charter.

This will ensure 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, the Risk Management Charter provides for: -

· The identification of Powerco’s Major Risk Areas incorporating all relevant programmes, processes, projects, activities and assets. · A standard framework and templates for the identification, assessment, acceptance and/or mitigation of risks across all Major Risk Areas. · Regular reporting of changes in the status of risks profiles, to alert management to any critical developments in Powerco’s overall Risk Management Profile. · Regular reporting to the Board on the levels of risk and management of that risk in all Major Risk Areas. · Reappraisal of Risk Management Plans by the Executive Management Team at six monthly intervals with findings reported to the Board through the Audit Committee

Steven Boulton Chief Executive

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Risk Management Overview

Objectives The objectives of the establishment of an integrated risk management process within Powerco are to: - · Ensure that significant risks currently faced by the business are understood and managed; · Develop an organisation-wide approach to business risk, including a common business risk language; · Prioritise risks on a business process basis rather than departmental basis; · Heighten awareness of risk and ensure that risk is considered in all decision making processes; · Ensure that there is a balance of management effort in relation to Opportunity Risks and Hazard Risks; · Ensure that all Powerco personnel are aware of their responsibilities in dealing with risks; · Ensure that significant risks are adequately monitored and controlled, through formal documentation and appropriate reporting channels; and · Ensure that adequate residual risk treatments such as insurance or internal funding are in place.

Benefits of Effective Risk Management The key benefits to Powerco and Powerco personnel of an effective risk management process are as follows: - · Facilitates better quality service delivery; · Protects personnel, intellectual property and assets; · Fosters legal and regulatory compliance; · Minimises the potential for litigation; · Promotes public, employee and consumer safety; · Achieves higher profitability through reduced expenses; and · Promotes effective internal management controls.

Process The process for the management of risk in Powerco is based on that described in SAA/NZS HB143: 199 Guidelines for Managing Risk in the Australian and New Zealand Public Sector. The following diagram is an overview of that process: -

Risk Management Overview

Establish the context

Identify risks

Analyse risks Monitor and review Evaluate risks Communicate and consult Evaluate risks

Assess risks

Treat risks

Risk management overview (AS/NZS 4360:1999)

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Main Elements The main elements of the risk management process include the following: -

· Establish the Context this step establishes the strategic, organisational and risk management context in which the rest of the process takes place. For the purposes of the initial implementation of the risk management process, criteria against which risk will be assessed is established and the structure of the analysis defined.

· Identify Risks identify Major Risk Areas and within those areas determine what, why and how things can arise as the basis for further analysis.

· Evaluate Risks determine the existing business processes and analyse risks in terms of probability of occurrence and impact in the context of those business processes. The analysis should consider:- · the likelihood of an event occurring; and · the potential consequences and their magnitude.

· Assess and Prioritise Risks compare estimated levels of risk against the pre-established criteria. Risks are then ranked to identify management priorities and appropriate action plans. The objective of this phase is to separate the major (or material/significant) risks, which require attention from the minor acceptable risks.

· Risk Response accept and monitor low-priority risks. For other risks develop and implement a specific management plan.

· Monitor and review monitor and review the performance of the risk management process and changes that might effect it.

The diagram below illustrates the key roles and components of the risk management process.

Key Roles and Components in Risk Management

BOARD

Risk management requirements Strategic Risk Management Risk Management Charter Framework

AUDIT COMMITTEE

Risk Management Charter Business Unit / Process Risk Reports / compliance Risk management strategies Management Profiles certificates

EXECUTIVE MANAGEMENT TEAM

Business Unit / Process Risk Delegations and accountabilities RISK Management Plans CUSTODIANS

Clear response Controls / self assessment Effective "buy-in" PERSONNEL

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Plans, Monitoring and Reporting

Risk management is an on-going cyclic process, as illustrated by the diagram below.

Powerco's Risk Management Cycle

Full risk identification & evaluation

Corporate Risk Management Coordination Development / modification of Risk Management Plans Risk response evaluation

Consolidated Reporting

Quarterly monitoring & review of Risk Profiles

The on-going monitoring and evaluation of risks and their management is conducted in the manner described below.

Audit Committee The Audit Committee is responsible to the Board for the governance of the Risk Management Process. Whilst the Risk Management Plans, draw up by the Risk Custodians are signed-off by the Executive Management Team, there must be an effective channel of communication through to the Audit Committee and Board.

Approval The communication and approval requirements are achieved by a quarterly reporting and review process in which reports are produced by the Risk Custodians and presented to the Executive Management Team for discussion. When accepted these reports are summarised by the Corporate Risk Manager, signed-off by the Executive Management Team and presented to the Audit Committee for approval.

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At six monthly intervals each Risk Management Plan is to be thoroughly reviewed by the assigned Risk Custodian and the results reported back to the Executive Management Team. Any revisions to the plans follow the same process as new plans with a sign-off required by the Executive Management Team.

Quarterly Management Review The Risk Custodians should review the detailed Risk Profile for each Major Risk Area assigned to them on a quarterly basis. At these reviews it should be identified whether there are any new perceived risks which need to be added to the Risk management Plan or whether existing risks need to be reassessed or are no longer relevant. In particular where new projects, processes or initiatives have been introduced; the Risk Custodian should consider what risks it is imposing on Powerco and amend the appropriate Risk Management Plan accordingly. It is possible that some instances of crossover between Major Risk Areas could occur here and so Risk Custodians need to communicate with each other and with the Corporate Risk Manager in a coordinating and supporting role as appropriate. This quarterly review should ensure that all material risks are being identified and that management is satisfied with their current risk profiles.

Reporting Risk Custodians should provide a Risk Management Report for their assigned Major Risk Area(s) on a quarterly basis. This report will document the findings and actions from the quarterly management review process. This will include:

· any alterations or additions to the Risk Attributes and/or Risk Responses · an update of the action list including any new actions · an amended Risk Management Profile if appropriate attached

The completed report should be forwarded to the Corporate Risk Manager with a copy attached to the appropriate Risk Management Plan as an addendum.

Six Monthly Reviews Every six months each Risk Custodian should take a fresh and rigorous risk management review on the Risk Management Plan. This should be more than a simple roll-forward of existing Plans but rather a full review, interviewing relevant employees and establishing Plans based on any new findings. The amount of time taken up by this process however should be minimal given that the quarterly review process has been thorough. Such review should include checks to ensure that: · all key strategies for managing risk are included; · any opportunity risk is identified; · one best KPI of the management risk is provided; and · all current and future actions set out in the Plan are directed towards managing risk.

The new and revised Plans should be presented, through the Corporate Risk Manager, to the Executive Management Team for sign-off. A summary report should explain the significant changes from the previous Plan and provide comment on the effectiveness of mitigating controls during the prior six-month period. The Corporate Risk Manager will then compile a summary report and revised overall Risk Management Profile through the Audit Committee to the Board.

This process of re-performing the identification and analysis on a six-monthly basis will ensure that the concepts behind the Risk Management Process remain fresh and it will encourage broader thinking than a review of an existing risk summary might elicit.

Once the Risk Management Process is established the six-monthly review cycles will be timed for November and May, so that the former fits into Powerco’s strategic planning and budget cycle. As part of the annual business review process the Executive Management Team will assess the Risk Management Process cycle to determine if any adjustments are deemed appropriate.

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Review and Reporting Cycle

Function Frequency Date Establishment of Risk Management Process Once As approved & Risk Management Plans Review and report on Risk Management Quarterly November Plans February May August Revise and up-date Risk Management Plans Six Monthly May November

This date cycle coincides with the biannual survey and reporting in Powerco’s Statutory Compliance Programme.

Consolidated Monthly Reporting The Risk Custodians are responsible for the on going Operational Risk Management Plans and for the quarterly and six-monthly review processes. Information will be extracted from these plans for consolidated monthly reporting of the status of each Risk Response including all outstanding items on the Risk Control Action Plan. The Corporate Risk Manager is responsible for the consolidation of this information and reporting to the Executive Management Team and the Board each month.

Risk Priority In order to provide a common basis on which to view and compare all business risks identified in all Major Risk Areas, each risk is assigned a priority derived from the evaluated consequential impact and residual risk probability on the following basis: -

Û Priority A (Red) - Risks assessed as HIGH impact and/or probability Ù Priority B (Blue) - Risks assessed as MEDIUM impact and/or probability Ö Priority C (Green) - Risks assessed as LOW impact and probability

Risk Register Each individual risk identified in the Operational Risk Management Plans is entered onto Powerco’s Consolidated Risk Register. This listing is reported in priority order and identifies the review dates and outstanding actions for each risk. The format for the Consolidated Risk Register is showing in the following example: -

Powerco Consolidated Risk Register Risk Name Priority Major Risk Risk Last Outstanding Actions Next A/B/C Area Custodian Review Review Date Date Price control A Regulation &Corporate Nov’00 1. Meet with Commerce Feb’01 threat Legal Risk Commission Compliance Manager 2. Submission to Price Control Paper

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Powerco Consolidated Business Risk Map Business Risk Map The Business ÛRisk MapEarthquake is a graphical representationÛ GXP of Lossthe identified individualÛ risksMajor plotted Storm onto a similar grid to the RiskÛ Profile Customer Summary. Credit This providesÛ a Treasuryquantitative analysis of the numbers of risks of each priority that fall into each sector of the profile of impact v probability. Û Work Hazards The format of the Business Risk Map is shown in the following example: - Ù Info.Systems Ù Load Shedding Û Price Control Ù Network Capacity Ù Asset Planning Û Generator Failure Ù Environ. Damage

Ö Pricing Methodology Ù Tech. Obsolescence Û Lightning Consequential Impact Ö Info. Disclosure Û Loss of Supply Ö Asset Maintenance

Residual Risk

Risk Control Action Plans are key risk management tools and in order to ensure that there is a strong management focus on these action plans all outstanding risk control actions will be incorporated into Powerco’s Consolidated Action Plan Register. This register will be used for the reporting and monitoring of actions from all high-level management functions including risk management. The analysis tools will be capable of reporting actions by type, business unit, priority, status, date, person responsible etc. This will enable sub-sets of the risk control actions to be reported in any desired grouping.

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Section Subject Date of Issue Page A2 Appendix 2: Powerco Regional Network Area Maps 30/06/02 95

Appendix 2: Powerco Regional Network Area Maps The maps on the following four pages show the Powerco asset management area and the locations of GXPs and zone substations.

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Powerco Information Disclosure Asset Management Plan Electricity Network 2003 – 2012