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ASSET MANAGEMENT PLAN

30 JUNE 2006

This document has been prepared by WEL Networks Ltd and may only be used for the specific purpose for which it was prepared; to meet the “Electricity Information Disclosure Requirements 2004 (Consolidating all amendments to 1 April 2006)”. No part of this publication may be reproduced or utilised in any form or by any means, electronic or mechanical, including photocopying and microfilm, without the permission in writing from the WEL Networks Ltd. Ownership of this document is vested in WEL Networks Ltd.

WEL Networks AMP 2006 – 2016 30 June 2006

ASSET MANAGEMENT PLAN WEL NETWORKS LTD Planning Period: 1 April 2006 to 31 March 2016 Disclosure Year: 2006 -07 Disclosure Date: 30 June 2006 WEL Networks Ltd PO Box 925 Hamilton Website: http://www.wel.co.nz Telephone: + 64 7 838 1399 Facsimile: + 64 7 858 1447 Liability Disclaimer Any information contained in this document is based on information available at the time of preparation. Numerous assumptions have been made to allow future resource requirements to be assessed. These assumptions may prove to be incorrect or inaccurate and consequently any of the future actions that are identified in this document may not occur. Users of the information contained in this document do so at their own risk. WEL Networks will not be liable to compensate any person for loss, injury or damage resulting from the use of the contents of this document. If any person wishes to take any action on the basis of the content of this document, they should contact WEL Networks for advice and confirmation of all relevant details before acting.


ASSET MANAGEMENT PLAN This Asset Management Plan has been considered by the WEL Networks Board and was approved at the June 2006 Board meeting.

Rodger Fisher Chairman


CHIEF EXECUTIVE’S STATEMENT The primary purpose of WEL Networks Ltd (WEL) is to provide customers in the Waikato with a safe, reliable and cost effective supply of electricity. Our aim is to be responsive to our customers’ needs, both for their current electricity supply and meeting their future requirements. The long life nature of our assets means that it is imperative that a detailed Asset Management Plan is in place. By listening to our customers, by benchmarking with other NZ line companies and by learning about trends overseas, WEL has established a number of objectives for its Asset Management Plan and these are detailed in the Plan. At a high level the following points are important. 1. In recent years we have had an ongoing programme of improving network-wide

reliability (measured by SAIDI) and have made significant capital investment to drive our reliability towards a target level of 50 SAIDI minutes by 2008. This Plan recognises a change in emphasis from capital investment to maintenance and fault work improvement, to achieving ongoing improved reliability.

2. A network-wide SAIDI target does not recognise challenges in parts of the

network, particularly in some of its rural areas. We are thus introducing a new target to ensure that the number of outages per customer is below prescribed levels.

3. Significant network investment took place 30-40 years ago. This Plan recognises

the importance of renewal and the methodologies to ensure that the optimal life is achieved from our existing assets.

4. This Plan and previous Plans show the “top down” approach that we have been

taking. This started at the transmission level. There have been capacity and quality upgrades at the Hamilton Grid Exit Point (GXP), a new GXP at Te Kowhai and a planned new GXP at Huntly. The 2006 AMP shows a strong emphasis on subtransmission and zone substations which will be followed by distribution and reticulation. This, of course, does not impede important investment in any part of our network.

5. There is strong economic growth in the Waikato and this requires capacity and

quality of supply in our networks. We have a programme of meeting with, and surveying customers, to ensure that their needs are best met going into the future.

6. For many years a long-term Asset Management Plan has been an important

strategic tool for WEL. Now that our plans have to be disclosed, we must also include the requirements of the regulator. This year, the Commerce Commission have required a range of additional information to be provided, and this Plan includes our response to these requirements.


7. This Plan reflects a growing emphasis on the maintenance of our network, so that even though we continue to make efficiency gains in maintenance, the overall maintenance spend will increase over the next 10 years.

We are planning to spend $188M over the next 10 years which is almost exactly equivalent to the doubling of the current asset value and this reflects a significant economic investment in the future of the Waikato.

M Underhill Chief Executive


WEL NETWORKS


CONTENTS Page 1 EXECUTIVE SUMMARY.............................................................................................................. 10

1.1 BACKGROUND AND OBJECTIVES.................................................................................... 10 1.2 ASSETS COVERED ............................................................................................................ 11 1.3 SERVICE LEVELS............................................................................................................... 12 1.4 NETWORK DEVELOPMENT PLANS.................................................................................. 13 1.5 LIFECYCLE ASSET MANAGEMENT PLANNING............................................................... 14 1.6 ASSET MANAGEMENT SYSTEMS AND PROCESSES..................................................... 16 1.7 RISK MANAGEMENT .......................................................................................................... 18 1.8 PERFORMANCE EVALUATION ......................................................................................... 18 1.9 AMP DISTRIBUTION IN 2005.............................................................................................. 18

2 BACKGROUND AND OBJECTIVES........................................................................................... 20 2.1 OWNERSHIP, MANAGEMENT STRUCTURE AND OPERATIONS DIVISION .................. 20 2.2 PURPOSE OF THE PLAN ................................................................................................... 20 2.3 CORPORATE PLANNING INTERACTION.......................................................................... 21 2.4 PLANNING PERIOD ............................................................................................................ 23 2.5 STAKEHOLDER INTEREST................................................................................................ 23 2.6 ASSET MANAGEMENT ACCOUNTABILITIES AND RESPONSIBILITIES......................... 24

3 ASSETS COVERED..................................................................................................................... 27 3.1 VALUE OF ASSETS IN EACH ASSET CATEGORY ........................................................... 27 3.2 DISTRIBUTION AREA DESCRIPTION................................................................................ 28

3.2.1 Asset Quantities............................................................................................................... 29 3.2.2 WEL Distribution Area ..................................................................................................... 30 3.2.3 Network Operations and Asset Management Priorities .................................................. 33 3.2.4 Network Load Characteristics.......................................................................................... 35 3.2.5 Peak Load and Total Electricity delivered. ...................................................................... 42

3.3 NETWORK CONFIGURATION............................................................................................ 42 3.4 AGE PROFILES, CONDITION ASSESSMENTS AND CURRENT MAINTENANCE PRACTICES FOR EACH ASSET CATEGORY ................................................................................ 43

3.4.1 Zone Substations............................................................................................................. 43 3.4.2 Zone Substation Transformers ........................................................................................ 44 3.4.3 33kV Circuit Breakers ...................................................................................................... 45 3.4.4 11kV Circuit Breakers ...................................................................................................... 46 3.4.5 33kV Sub-Transmission Underground Cables ................................................................ 47 3.4.6 33kV Overhead Lines ...................................................................................................... 48 3.4.7 Distribution 11kV Underground Cables ........................................................................... 49 3.4.8 Distribution 11kV Overhead Lines ................................................................................... 50 3.4.9 11kV Switching Stations .................................................................................................. 51 3.4.10 11kV Ring Main Units.................................................................................................. 52 3.4.11 11kV Air Break Switch (ABS) ...................................................................................... 53 3.4.12 11kV Reclosers and Sectionalisers............................................................................. 55 3.4.13 Distribution transformers ............................................................................................. 56 3.4.14 LV underground cables ............................................................................................... 58 3.4.15 LV Overhead Reticulation ........................................................................................... 58 3.4.16 SCADA; Communications and Control Equipment ..................................................... 59 3.4.17 Load Control Equipment.............................................................................................. 60

3.5 NETWORK ASSET JUSTIFICATION. ................................................................................. 61


4 SERVICE LEVELS ....................................................................................................................... 64 4.1 CONSUMER PERFORMANCE TARGETS ......................................................................... 64

4.1.1 Safety............................................................................................................................... 64 4.1.2 Reliability.......................................................................................................................... 64

4.2 OTHER PERFORMANCE TARGETS - ASSET EFFICIENCY, EFFECTIVENESS AND EFFICIENCY OF BUSINESS ACTIVITY........................................................................................... 67

4.2.1 Operating Efficiency - CPC.............................................................................................. 67 4.2.2 Asset Efficiency ............................................................................................................... 67 4.2.3 Low Voltage Complaints .................................................................................................. 68

4.3 JUSTIFICATION FOR TARGET LEVELS OF SERVICE ..................................................... 68 4.3.1 Customer Surveys ........................................................................................................... 68 4.3.2 Setting Reliability Targets ................................................................................................ 71

5 NETWORK DEVELOPMENT PLANS ......................................................................................... 74 5.1 PLANNING CRITERIA AND ASSUMPTIONS. .................................................................... 74 5.2 PRIORITISATION METHODOLOGY FOR DEVELOPMENT PROJECTS.......................... 74 5.3 DEMAND FORECASTS....................................................................................................... 75

5.3.1 Changing Load Patterns and Demand Side Management.............................................. 76 5.3.2 Forecast Loads ................................................................................................................ 76 5.3.3 Grid Exit Points ADMD .................................................................................................... 77

5.4 GROWTH RELATED NETWORK CONSTRAINTS ............................................................. 77 5.5 DISTRIBUTED GENERATION POLICY .............................................................................. 78 5.6 NON-NETWORK SOLUTION POLICY ................................................................................ 79 5.7 NETWORK DEVELOPMENT PROGRAMME AND ANALYSIS OF NETWORK DEVELOPMENT OPTIONS.............................................................................................................. 79 5.8 EXPENDITURE PROJECTIONS......................................................................................... 87

6 LIFECYCLE ASSET MANAGEMENT PLANNING ..................................................................... 89 6.1 MAINTENANCE PLANNING CRITERIA.............................................................................. 89

6.1.1 Drivers and Strategy ........................................................................................................ 89 6.1.2 Optimisation Process....................................................................................................... 89

6.2 MAINTENANCE PROGRAMME BY ASSET CATEGORY WITH EXPENDITURE PROJECTIONS................................................................................................................................. 90

6.2.1 Programme ...................................................................................................................... 90 6.2.2 Expenditure Projections................................................................................................... 91

6.3 ASSET RENEWAL POLICY................................................................................................. 92 6.4 ASSET RENEWAL PROGRAMME WITH EXPENDITURE PROJECTIONS. ..................... 94

6.4.1 Zone Substation Transformers ........................................................................................ 95 6.4.2 33kV Circuit Breakers ...................................................................................................... 95 6.4.3 11kV Circuit Breakers ...................................................................................................... 95 6.4.4 33kV Sub-Transmission Underground Cables ................................................................ 95 6.4.5 33kV Overhead Lines (Conductor and Poles)................................................................. 95 6.4.6 Distribution 11kV Underground Cables ........................................................................... 96 6.4.7 Distribution 11kV Overhead Lines ................................................................................... 96 6.4.8 11kV Switching Stations .................................................................................................. 96 6.4.9 11kV Ring Main Units ...................................................................................................... 96 6.4.10 11kV Air Break Switch (ABS) ...................................................................................... 97 6.4.11 11kV Reclosers and Sectionalisers............................................................................. 97 6.4.12 Distribution transformers ............................................................................................. 97 6.4.13 LV underground cables ............................................................................................... 97 6.4.14 LV Overhead Reticulation ........................................................................................... 97 6.4.15 SCADA; Communications and Control Equipment ..................................................... 98 6.4.16 Load Control Equipment.............................................................................................. 98 6.4.17 Total Asset Renewal Budget ....................................................................................... 99

7 ASSET MANAGEMENT SYSTEMS AND PROCESSES.......................................................... 101 7.1 ASSET MANAGEMENT PROCESSES ............................................................................. 101

7.1.1 High Level Process Interaction ....................................................................................... 101 7.1.2 Asset Inspections and Network Maintenance ............................................................... 102 7.1.3 Network Development Projects ..................................................................................... 103


7.1.4 Network Performance Measurement............................................................................. 104 7.2 KEY ASSET DATA SYSTEMS INCLUDING DATA GAPS AND IMPROVEMENT INITIATIVES.................................................................................................................................... 105

7.2.1 GIS (Geographic Information System) .......................................................................... 105 7.2.2 SCADA (Supervisory Control and Data Acquisition) ..................................................... 105 7.2.3 OMS (Outage Management System) ............................................................................ 106 7.2.4 Contingency Plan Management System ....................................................................... 106 7.2.5 ICP (Installation Control Point) ...................................................................................... 106 7.2.6 Call Centre Management System.................................................................................. 107 7.2.7 Capital Works Library (CALIB) ...................................................................................... 107 7.2.8 PSS Adept ..................................................................................................................... 108 7.2.9 MAXIMO ........................................................................................................................ 108 7.2.10 DMS (Distributed Management System)................................................................... 109 7.2.11 SQL OLAP and Slice and Dice.................................................................................. 109

7.3 SYSTEMS DATA FLOW .................................................................................................... 109 7.4 SYSTEM AND DATA OWNERSHIP .................................................................................. 109

8 RISK MANAGEMENT ................................................................................................................ 111 8.1 RISK FRAMEWORK .......................................................................................................... 111 8.2 RISK ANALYSIS ................................................................................................................ 111

8.2.1 Identifying Risks............................................................................................................. 111 8.2.2 Evaluating Risk .............................................................................................................. 112 8.2.3 Ranking of Risk.............................................................................................................. 113 8.2.4 Treatment Options ......................................................................................................... 113 8.2.5 The Risk Management Committee ................................................................................ 114 8.2.6 Prioritisation ................................................................................................................... 115 8.2.7 Monitoring ...................................................................................................................... 115

8.3 NETWORK RISK................................................................................................................ 115 8.4 EMERGENCY RESPONSE AND CONTINGENCY PLANNING........................................ 115

9 PERFORMANCE EVALUATION ............................................................................................... 117 9.1 CAPITAL EXPENDITURE.................................................................................................. 117

9.1.1 Gap Analysis and Improvement Initiatives. ................................................................... 117 9.2 NETWORK DEVELOPMENT PROGRAMME.................................................................... 119

9.2.1 Gap Analysis and Improvement Initiatives .................................................................... 120 9.3 MAINTENANCE EXPENDITURE ...................................................................................... 121 9.4 SERVICE LEVELS AND ASSET PERFORMANCE........................................................... 123

9.4.1 Safety............................................................................................................................. 123 9.4.2 Reliability........................................................................................................................ 123 9.4.3 Low Voltage Complaints ................................................................................................ 124 9.4.4 Gap Analysis and Improvement Initiatives .................................................................... 125

APPENDIX 1 – GLOSSARY OF TERMS ........................................................................................... 127

APPENDIX 2 – LOAD GROWTH TABLE FOR ZONE SUBSTATIONS ........................................... 131


EXECUTIVE SUMMARY

1.1 BACKGROUND AND OBJECTIVES WEL Networks Limited (hereafter referred to as WEL) is owned wholly by the WEL Energy Trust, a community trust. In disclosing this Asset Management Plan document WEL is proud to advise and show its confidence in investing in the network asset at a record level of capital expenditure, asset renewal and maintenance. This investment fully supports the Waikato economic indicators and community customers into an exciting and challenging future. This Document which presents the Asset Management Plan (AMP) is prepared for the following purposes:

• "To enable WEL to provide the required level of services cost effectively through

the creation, operation, maintenance, renewal and disposal of assets to meet the needs of existing and future customers".

• “To provide a working document for use by WEL in conjunction with other

detailed planning and implementation processes and activities as described herein.

• “To provide stakeholders with the level of information required to make an

informed judgement as to the extent that WEL’s asset management processes meet Best Practice criteria”.

• “To satisfy the “Electricity Information Disclosure Requirements 2004

(Consolidating all amendments to 1 April 2006)”. WEL seeks to apply international “Best Practice” asset management and planning processes integrated with strategic business plans and goals. The corporate strategic drivers for this are derived from WEL’s Mission and Vision statements which are: WEL’s Vision:

• To be a World-Class Supplier of Energy and Network Services focused on Customer Service and Value Creation.

WEL’s Mission:

• Providing high quality reliable services to customers and achieving excellent returns, while growing the business to be a major regional utility.

This Asset Management Plan was approved at the June 2006 Board Meeting by the Board of Directors and relates to a period of 10 years from the financial year beginning on 1 April 2006 until the year ended 31 March 2016. The main focus of the analysis is the first 5 years and for this period most of the specific projects have been identified. Beyond this period, analysis is subject to less certainty.


1.2 ASSETS COVERED The assets covered by this plan and the ODV valuation are:

Asset Category Asset Value $000

Zone Substations 4,669Zone Substation transformers 6,57433kV Circuit Breakers 1,80711kV Circuit Breakers 6,31433kV Sub-Transmission Underground Cables 10,04633kV Overhead Lines 8,316Distribution 11kV Underground Cables 23,386Distribution 11kV Overhead Lines 39,00211kV Switching Stations 5,38111kV Ring Main Units 3,02711kV Air Break Switch 2,70311kV Reclosers and Sectionalisers 360Distribution Transformers 24,423LV Underground Cables 31,726LV Overhead Reticulation 18,010SCADA; Communications and Control Equipment 2,604Load Control Equipment 683Other 464

Total $189,495Figure 1.1 – ODV valuations for each asset category. The geographical area covered by WEL’s network extends from Meremere in the north Waikato to Hamilton in the south and Raglan to the East of Morrinsville. This is shown diagrammatically in Section 3.2 and consists of: 4 Transpower Grid Exit Points, 18 zone substations, approximately 273km of 33kV sub transmission circuits, 2500km of 11kV distribution circuits, 77,000km of low voltage circuits and associated transformers, switches and equipments. A peak demand of 223MW is recorded for the winter 2005. The security levels for the network is predominantly N-1 for urban, industrial, CBD, commercial and some rural. Other areas have N-1 with restoration after switching. The remainder generally in remote rural has N security.


1.3 SERVICE LEVELS WEL’s goal is to provide a quality product to all consumers. WEL defines quality as “providing a network that is safe, reliable and fit for purpose”. Out of the factors contained within the definition WEL places primary importance on safety. As such safety practices are chosen to be consistent with industry best practice. These are measured using the indicators described below. Reliability is also a critical performance indicator. Appropriate levels of reliability are determined by combining customer survey results with benchmarking studies and by taking implementation costs into account. The views and opinions of customers are treated with utmost importance by WEL. Twice yearly seminars are held with major industrial and commercial customers. At those seminars reliability and other issues are discussed, with the specific aim of educating and discussing the price quality trade-off. Based on those discussions, plans are formulated to ensure the required quality of supply is provided. Comparison of collective customer survey reliability expectations, shown below with WEL’s strategic performance targets (50 SAIDI minutes, SAIFI of 1 and 50 CAIDI minutes by 2007/2008) shows that WEL’s reliability targets exceed customer expectations.

Calculated SAIDI from Survey Result (excluding 400V)

Input from survey OutputAcceptable Outage

Number / Customer / Year

Average duration (minutes)

SAIDI (minutes) SAIFI CAIDI

(minutes)

CBD 1 41 0.03 0.00 41.00IND-M 2 34 0.06 0.00 34.00URB-C 1 35 2.27 0.06 35.00URB-R 2 53 34.78 0.66 53.00RDL 3 56 20.50 0.37 56.00Rural 4 77 0.25 0.00 77.00Grand Total 57.89 1.09 52.97

Customer Group

Figure 1.2 – SAIDI Survey results. WEL’s historical performance has dramatically improved from 131 SAIDI minutes, 5 years ago down to 69.63 SAIDI minutes by end of March 2006. This is moving WEL towards the New Zealand Best Practise Index trace (NZBPI) developed by WEL.


1.4 NETWORK DEVELOPMENT PLANS WEL has entered into a record level of Capital Expenditure (CAPEX) over the next ten years to meet customer needs through growth, security level demand, quality of supply and regulatory requirements. To achieve this WEL has developed analytical tools and processes. Throughout the year WEL builds up a list of capital development projects aimed to address issues of customer needs, security, compliance, reliability, load growth, asset replacement and security standards for the planning period under consideration. Demand forecasting, demand side management, generation and load management form part of this process to develop appropriate network solutions. These network development projects are extensive and include:

• A new Grid Exit Point (GXP) installation at Huntly.

• Seven new zone sub stations.

• Extensive new 33kV sub transmission and distribution 11kV cabling.

• Seven zone transformer capacity upgrades.

• Automation for reliability projects.

• 11kV and LV cable augmentation and interconnections.

• 1500 sections of subdivision reticulation per annum.

• Protection and communication upgrades and development.


Capital expenditure for these projects is reflected in the following graph.

WEL's 10 Year Capital Expenditure Projection

-

5,000

10,000

15,000

20,000

25,000

30,000

06/07 07/08 08/09 09/10 10/11 11/12 12/13 13/14 14/15 15/16

$000

Communication

Undergrounging

Reliability

Security - POS

Load Grow th Projects

Customer Connections - WEL

Compliance

Asset Replacement

Figure 1.3 – Capital Expenditure Projection for AMP period

1.5 LIFECYCLE ASSET MANAGEMENT PLANNING WEL has entered into a high level of maintenance and renewal expenditure over the next ten years to ensure the asset base is adequately maintained and renewed to reflect customer security and WEL’s business objectives. This is reflected in the following maintenance expenditure table:

WEL's 10 Year Maintenance Spend Profile

0

500

1000

1500

2000

2500

3000

3500

4000

4500

5000

06/07 07/08 08/09 09/10 10/11 11/12 12/13 13/14 14/15 15/16

$000

Faults External SubdivisionSCADAZone SubstationsVegetation ManagementDistribution LinesRelocationsFaults

Figure 1.4 – Maintenance Expenditure Projection for AMP period.


Reliability Centred Maintenance (RCM) is used as the primary driver for maintenance taking into account plant performance and function rather than the asset itself. Other maintenance techniques are employed to achieve World Class maintenance practice including Root Cause Analysis (RCA) and Failure Mode Effects and Criticality Analysis (FMECA). A long term asset renewal strategy has been established with increasing attention being paid to asset replacement management. An asset renewal plan has been developed to ensure the continued high performance of in-service network assets, in particular older assets, through refurbishment and replacement strategies for each class of asset. The program identifies the need to continue to renew assets to allow service levels and customer expectations to be met. The decision to undertake to renew an asset is based on age as well the following factors:

• Performance evaluation

• Asset condition monitoring

• Level of refurbishment, maintenance and operating costs

• Historical failure statistics

• A risk assessment associated with deferring asset replacement expenditures This is reflected in the following renewal expenditure table:

WEL's 10 Year Asset Renewal Capital Projection

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

06/07 07/08 08/09 09/10 10/11 11/12 12/13 13/14 14/15 15/16

$000

Others

Zone Substation Transformer

SCADA Equipment -RTU

LV Underground cables

LV Overhead Reticulation

Load Control Equipment

Distribution Transformers(11kV / 400V)

Distribution 11 KV UG cables

Distribution 11 KV OH Lines

33KV Sub-transmission UG cable

33 KV Overhead Lines

33 KV Circuit Breaker

11KV Reclosers and Sectionalisers

11KV A ir Break Sw itch

11 KV Sw itching Station

11 KV Ring Main unit


Figure 1.5- WEL’s 10 Year Asset Renewal Expenditure projection.


1.6 ASSET MANAGEMENT SYSTEMS AND PROCESSES WEL uses a number of management systems and processes for complete management of the asset. The relationships between the high level processes are shown in the following diagram:

Asset Performance

required by owner under cost constraints

AssetStrategyPlanning

AssetGrouping

StandardsDevelopment

AssetLife

Planning

Network Life Plan (made up of ALPs)

to meet performance

requirements for given cost

Network Planning

Data Collection and Validation

Performance Management

Customer Requirements

Maintenance Optimisation

Figure 1.6 - Interaction between high level asset management processes. The various complimenting processes include:

• Asset Strategy Planning: This process generates and evaluates high-level investment and maintenance strategies, and confirms these strategies with the Asset Owner.

• Asset Grouping: This describes the process, rules and conventions regarding

the creation and manipulation of assets into groups for efficiency and other purposes.


• Network Planning: This process develops project plans and optimises them with consideration of cost, performance and risk to produce both the Asset Management Plan and Work Plan.

• Standards Development: This describes the process, rules and conventions

regarding the standards required to manage the network.

• Asset Life Planning: This process pulls asset data together into cohesive plans for the life of a given asset or group of assets, considers the OPEX/CAPEX trade-off and combines these into an overall Asset Life Plan.

• Data collection and validation: This describes the process, rules and

conventions regarding the definition, capture, storage and validation of asset data.

• Maintenance optimisation: This process develops maintenance plans and

optimises them with consideration of cost, performance and risk to produce both the Asset Management Plan and Work Plan.

Under each of the master processes are a number of detailed procedures and work method statements, three of which are described in 7.1.2, 7.1.3 and 7.1.4. Key information systems include:

• GIS

• SCADA

• Outage Management System

• Contingency Planning

• Capital Works Library

• Load Flow and Analysis Software tools

• Maintenance Management System

• Distributed Management System Data quality gaps have been identified and improvement initiatives have been put in place for the above systems. These complimentary processes allow a cohesive system for WEL to manage the network asset.


1.7 RISK MANAGEMENT WEL recognises risk management to be critical in achievement of its Vision and Mission statements. WEL has a clearly defined Risk Management Policy, which is published on the company Intranet. This Policy and supporting procedure identifies risk management as a core management responsibility and outlines in broad terms the emphasis given to this in both the day-to-day and longer-term facets of managing its assets and overall business. The Policy shows Risk Management to be an integral part of the management (including asset management) and operating structure designed to improve decision-making leading to minimisation of losses and maximisation of opportunities. WEL has developed and maintains a “risk aware” culture with employees empowered and enabled to identify all relevant risks and has in place processes to evaluate, prioritise and manage the risks with the appropriate balance of costs verses consequences and likelihood. This is achieved by systematic application of processes to identify, analyse, evaluate, prioritise, treat and monitor any situations where undesired or unexpected outcomes could be significant or where opportunities could ensue.

1.8 PERFORMANCE EVALUATION WEL checks its performance through a variety of measures which include:

• Overall actual Capital Expenditure matched against AMP forecast.

• Maintenance Expenditure matched against budgeted forecast.

• Network Development Programme Gap.

• Service Levels and Asset Performance for safety and reliability (SAIDI, CAIDI, SAIFI).

• Low Voltage Complaints received and the number proven for comparison.

Performance gap analysis and improvement initiatives have been put in place.

1.9 AMP DISTRIBUTION IN 2005 Last year the AMP was provided to:

• Three Lines Companies


• One Generator

• Three Consultants

• Two Suppliers

• One other interested party.

No end customers requested a copy of the Asset Management Plan.


2 BACKGROUND AND OBJECTIVES 2.1 OWNERSHIP, MANAGEMENT STRUCTURE AND OPERATIONS DIVISION WEL is 100% owned by a community trust, the WEL Energy Trust. The Trust appoints the directors who appoint the Chief Executive. WEL has Operations and Corporate Services Divisions. The executive team is as shown in figure 2.1. Executive Team

Figure 2.1 – WEL’s Executive Team The Chief Executive is Mike Underhill, BE (Elect), MCom (Hons), FIPENZ. The General Manager Operations is Russell Shaw, BEng (Hons), MSc, CEng, MIEE, MIPENZ. The Operations Division has overall responsibility for management of the network assets. This includes ensuring that the assets are developed, renewed, maintained operated and used in a long term sustainable basis to meet the needs of all stakeholders. Within the Operations division there are seven teams that address: Asset Investment, Performance & Quality, Health, Safety and Compliance, Capital Projects, Field Services, Procurement and Real Time operations. For a detailed Operations organisational structure and a description of asset management accountabilities and responsibilities refer to section 2.5. 2.2 PURPOSE OF THE PLAN This AMP is prepared for the following purposes:

GM Operations

Russell Shaw

GM Corporate Services

Kevin Palmer

Customer Services and Development

Jack Ninnes

Generation

Roger Burchett

Chief Executive Mike Underhill


• "To enable WEL Networks to provide the required level of services cost effectively through the creation, operation, maintenance, renewal and disposal of assets to meet the needs of existing and future customers".

• “To provide a working document for use by WEL in conjunction with other

detailed planning and implementation processes and activities as described herein.

• “To provide stakeholders with the level of information required to make an

informed judgement as to the extent that WEL’s asset management processes meet best practice criteria”.

• “To satisfy the “Electricity Information Disclosure Requirements 2004

(Consolidating all amendments to 1 April 2006)”. 2.3 CORPORATE PLANNING INTERACTION Best practice asset management and planning processes are integrated with strategic business plans and goals. The corporate strategic drivers for this are derived from WEL’s Mission and Vision statements which are: WEL’s Vision:

• To be a World-Class Supplier of Energy and Network Services focused on Customer Service and Value Creation.

WEL’s Mission:

• Providing high quality reliable services to customers and achieving excellent returns, while growing the business to be a major regional utility.

WEL’s asset management practices are consistent with company vision and mission statements and as such are designed to provide the required levels of service at least cost. To ensure the link between corporate strategic drivers and asset management practice is maintained, WEL seeks to: Provide a network that will meet future demands safely and reliably, through; understanding electricity volumes, energy demands, asset lifetime requirements, new technology, optimal maintenance and replacement programmes, assessment of risk and reliability, safety of network operation, capital improvement, using skilled labour and appropriate materials and ensuring an ongoing commercial return.

• Continually improve reliability through a segmented customer approach by

understanding and educating customers on the price / quality trade-off, delivery of reliability expectations and targeting the worst performing network components.

• Deliver efficiency and performance through improving processes, operating

a performance based organisation and aligning with industry benchmarks.


Link between Corporate Strategic Drivers and Asset Management

Corporate Strategic Objectives

Strategic AM planning workshops with Board and Management to develop high level AM strategies

Legislative Requirements Customer Expectations

Service LevelsTypes of service

Strategic Asset Management Process

Application of strategies and prioritisation to:

Feedback∪ Business strategies∪ Knowledge management

(GIS & IT)∪ Benchmarking & KPI’s∪ Risk assessment∪ Audits

Existing Assets New Asset Investment Surplus Assets

MaintainReplaceEnhance

Non AssetInvestigationsConstruction

Dispose or

Mothball?

Strategic Asset Management

∪ Coordination of AMP activity

∪ “Needs analysis”∪ AMP improvement∪ Prepare/revise AMP

Asset Management Plan Update

GovernanceAnnual Business Plan

Asset Management Planand Budget Approval

Review strategic planning outputs

against:

∪ Market forces∪ Market changes∪ Business focus∪ AM Strategies

IMPLEMENTATON

Customer Needs and Expectations

Diagram Reference: 171697 Figure 2.2 – Flowchart Representation of the link between Corporate Strategic Drivers and Asset Management.


From the flowchart the following points of interest are noted.

• Strategic policy feeds directly into the development of asset management

practice.

• Asset management practice is captured in the Asset Management Plan for long term development and maintenance.

• The AMP provides the capital and maintenance expenditure projections for the

next 10 years. This is the main input into the Strategic and Business Planning Processes. From this the annual works plan is produced.

• The governance activity and approvals occur prior to implementation.

2.4 PLANNING PERIOD This Asset Management Plan was approved at the June 2006 Board Meeting by the Board of Directors and relates to a period of 10 years from the financial year beginning on 1 April 2006 until the year ended 31 March 2016. The main focus of the analysis is the first 5 years and for this period most of the specific projects have been identified. Beyond this period, analysis is subject to less certainty. 2.5 STAKEHOLDER INTEREST WEL has many stakeholders who have different interests as follows:

Stakeholder Main interests

WEL Energy Trust Strategic Direction, Monitoring performance, Dividend, Value of Company & Community Profile

End use Customers Price, Reliability, Safety, Responsiveness. Retailers Cost, Reliability Regulator Comparative costs, Reliability, Rate of Return, Price Public Safety, Environmental Responsibility.

Figure 2.3 – Stakeholder interests. For the public and end use customers WEL identifies what stakeholder interests are by way of customer surveys, forums and newsletters. Regulator interest is determined by sourcing the appropriate regulation and legislation. WEL Energy Trust expresses its’ interest by commissioning a technical advisor to review the AMP and provide feedback. Finally, WEL determines the Retailer’s interest by conducting a series of regular meetings to discuss customer issues. Stakeholder interests are accommodated by applying five key tenets to Asset Management;


• Maintaining a clear focus on providing a safe and high quality service to customers.

• Achieving levels of reliability which meet or exceed customer expectations on

reliability and price.

• Balancing the needs of Shareholders, Customers and Users.

• Effectively managing risk.

• Achieving excellent returns by improving operating efficiency and optimising investment decisions.

Full commitment and a balanced application of these five tenets are critical for the successful implementation of WEL’s asset management philosophy. 2.6 ASSET MANAGEMENT ACCOUNTABILITIES AND RESPONSIBILITIES Responsibility for asset management occurs on several levels of which the key levels are through; governance by the Board of Directors, executive management and planning and field services implementation. Governance is achieved by the Board of Director’s through; annual review of the 5 yearly strategic plan, annual review and approval of the AMP, annual review and approval of the business plan and budgets, monthly review and decision-making on required actions that vary from original plans. Additionally, the Board receives the following each month; a detailed reliability report with an explanation of outages incurring more than 0.5 SAIDI, a report on Transpower peak demand achieved versus budget, a report on customer complaints, a report on voltage complaints, a report on the performance framework for reliability and a corrective action plan for improvement. All reports are produced by management. Executive and senior management have accountabilities and responsibilities to the board of directors for; preparation of the AMP, delivery of the works programme, investment optimisation, risk analysis, safety of the system, economic performance of the network, measurement of asset performance, performance reporting and reporting variation from current plans. Maintenance, faults and small capital works previously provided by an external contractor as alliance partner are now carried out by WEL Staff. This is due to pressure on the skilled labour market and the desire to have a direct relationship with core staff. For field operations a work plan is produced annually from the approved Business Plan and a budget which sets the number of work units required. Examples of work units include routine inspections, Circuit Breaker maintenance and trees cleared. Monthly reports which monitor the work performance against that planned are provided by the Field Services group. Capital works over $100k are competitively tendered to approved contractors. There are also 3-5 year contracts awarded to contractors to complete work such as 7 new


zone substations. These include 2 technical contracts, 2 cable contracts and 1 jointing contract for large capital projects. The structure of the Operations Division is shown in figure 2.4.


Manager

1 x Project Manager

9 x Civil2 x Trainee

3 x GIS & Data Administrators 1 x Admin1 x lineman

2 x Jointers4 x Electrical Fitters2 x Civil worker4 x Trainees1 x Admin

1 x Admin7 x Estimators / PMs2 x Project Administrators

9 x Lineman/faultman6 x Live Lineman4 x Trainee2 x Admin

3 x Technicians1 x Trainee

General Manager Operations

H, S & Compliance Manager

Compliance Manager

SysCon ManagerProcurement ManagerField Services Manager

1 x Control Systems Manager1 x Control Centre Co-ordinator6 x Shift Operators

1 x Distribution Centre Supervisor1 x Purchase Co-ordinator1 x Inward Goods Storeperson1 x Outwards Goods Storeperson

Maintenance StrategyManager

Performance & Quality

Quality Audit Manager(Part Time)

Network Assessor

Asset Investment

Capital Projects Manager

GIS and Data ManagerDistribution TechnologySpecialist

System Architect

Advisor

Asset Investment Manager

Project Supervisor

Works Co-Ordinator

Field Substations ManagerElectrical Supervisor

Technical Services Supervisor

Customer Service Manager

Supervisor, Lines

Maximo CoordinatorExternal Works Manager

Field Projects Manager

Figure 2.4 – Operations Organisational Structure.


3 ASSETS COVERED 3.1 VALUE OF ASSETS IN EACH ASSET CATEGORY Asset Values are included in figure 3.1. The figures were obtained from the latest ODV valuation performed in 2004.

Asset Category Asset Value$000

Zone Substations 4,669

Zone Substation transformers 6,574

33kV Circuit Breakers 1,807

11kV Circuit Breakers 6,314

33kV Sub-Transmission Underground Cables 10,046

33kV Overhead Lines 8,316

Distribution 11kV Underground Cables 23,386

Distribution 11kV Overhead Lines 39,002

11kV Switching Stations 5,381

11kV Ring Main Units 3,027

11kV Air Break Switch 2,703

11kV Reclosers and Sectionalisers 360

Distribution Transformers 24,423

LV Underground Cables 31,726

LV Overhead Reticulation 18,010

SCADA; Communications and Control Equipment 2,604

Load Control Equipment 683

Other 464

Total 189,495Figure 3.1 – Asset Value by Category For details pertaining to the age, condition and maintenance programmes for each asset category refer to section 3.3. For asset renewal programme information refer to section 6.4.


3.2 DISTRIBUTION AREA DESCRIPTION This section shows WEL’s asset quantities and the entire network broken down into supply zones. A description of the effect that consumers have on network operations and asset management priorities is also given. Furthermore a customer type breakdown is displayed in pie charts for each supply zone. Finally, for WEL’s entire network the peak demand and total energy used in the 2005/2006 financial year are given.


3.2.1 Asset Quantities

A list of WEL’s asset quantities is given in figure 3.2. ASSET CLASS Unit Total Units Subtransmission 33kV Lines km 190 33kV Cables km 83 Pilot / Communications (O/H & U/G) km 216 33kV Isolation and Surge Arrestors No. 19 33kV Outdoor Circuit Breakers No. 36 Zone Substations Site Development and Buildings No. 35 Transformers – Extended Life No. 32 Switchgear Cubicles and Indoor Switchgear No. 281 Incoming (Outdoor) Switchgear, Protection and Controls

No. 333

Outdoor Structure Concrete No. 13 SCADA and Communications Equipment No. 34 Ripple Injection Plant No. 16 LV and DC supplies No. 38 Other items No. 50 Distribution 11kV Lines km 2,088 11kV Cables km 447 Disconnectors, Load Break Switches, Dropout Fuses

No. 5,651

Sectionalisers, reclosers, Circuit Breakers, Ring Main Units, Switches

No. 705

Distribution Lightning Arrestor No. 649 Voltage Regulators No. 13 Distribution Transformers No. 4,731 Distribution Substations No. 4,742 LV Lines km 1,141 LV Cables km 852 LV Street lighting Lines km 115 Streetlight Cables km 153 Link Pillars No. 570 Customer Service Connections LV Overhead No. 36,874 LV Underground No. 36,874

Figure 3.2 – List of Asset Quantities - Data was sourced from the most recent ODV Report performed in 2004.


Figures 3.4 and 3.5 indicate the areas WEL supplies. Figure 3.4 shows the entire network and indicates zone substations situated outside Hamilton City. Figure 3.5 shows Hamilton City and indicates zone substations located within city boundaries. The corresponding area supplied by each zone substation is also indicated. Both figures 3.4 and 3.5 use WEL acronyms for zone substations. The full name for each acronym along with zone substation capacity and the number of customers supplied by each zone substation is indicated in figure 3.3.

Three Letter code Full Name Installed Capacity

(MVA)

Customers Supplied

AVA Avalon Dr 46 5,329

BRY Bryce St 46 3,368

CHA Chartwell 46 7,112

CLA Claudelands 36 7,040

FIN Finlayson Rd 7.5 1,092

GLA Glasgow St 10 2,437

GOR Gordonton 10 1,477

HOR Horotiu 20 3,961

KEN Kent St 46 3,769

LAT Latham Court 30 4,143

PEA Peacockes Rd 20 4,314

PUK Pukete 11 30 2,032

SAN Sandwich Rd 46 5,704

TEK Te Kauwhata 10 1,486

TEU Te Uku 10 2,903

WAL Wallace Rd 20 5,868

WEA Weavers 15 3,472 Figure 3.3 – Zone substations – Full name, abbreviation, capacity and customers supplied. A full breakdown of the supply zones by customer type is given in section 3.1.3.

3.2.2 WEL Distribution Area WEL supplies power to Hamilton City, Raglan, Gordonton, Horotiu, Ngaruawahia, Huntly, Te Kauwhata and Maramarua. In addition the rural areas surrounding those centres are also supplied by WEL.


Figure xx: Entire Region supplied by WEL. Non-Hamilton zone substations and associated supply areas are indicated.

Region supplied by Hamilton City Zone Substations

Figure 3.4 Zone substations situated outside of Hamilton city and associated supply zones.


Figure 3.5: Hamilton City zone substations and associated supply zones.


3.2.3 Network Operations and Asset Management Priorities WEL controls network operations in real-time from System Control (SYSCON). SYSCON is staffed by shift operators who are responsible for ensuring continuity and quality of supply to WEL’s customers in real-time. In addition to SYSCON, WEL uses a Call Management Centre for handling customer phone calls, daytime dispatch of faults staff to investigate all faults and night time dispatch of faults staff to correct low voltage faults. WEL treats all supply issues with urgency. The focus during restoration is on restoring supply as quickly as possible while operating in a manner which is safe to personnel, the public and property. However in situations where multiple faults have taken place, resources have to be prioritised to restore all supplies. Due to the company goal of minimising SAIDI, the fault affecting the most customers would normally be addressed first. The exception to this is where one of the supplies affected is likely to have an effect on the public good or have a serious economic impact to one or more parties. In such cases the priority order is reversed. For example customers with critical supplies such as those requiring dialysis, flood pumps and dairy farms would be prioritised ahead of others. WEL’s Network Planning function has responsibility for determining the network investment required to address security issues. The policy is to provide a level of security which is proportional to the load magnitude. Therefore higher magnitude loads are likely to be provided with higher levels of security whereas lower magnitude loads will be provided with a lower level of security. The cost of providing a certain level of security is also taken into account. Projects designed to improve security are prioritised using the table in figure 3.5 to assess what level of security is appropriate for each specific case. By examining WEL customer information and referring to the security class definitions in figure 3.6 the following points are noted.

• At the zone substation level currently 25% of WEL customers have a C1 security level, 63% have a C2 level, 9% have a B1 level and 3% have a B2 level. As security levels B3 and A relate to feeders and security level D relates to the point of supply level those security classes are not considered in this analysis.

• 99% of WEL’s customers have an alternate supply under switching.

• Security levels provided to WEL customers are consistent with or exceed

those required in figure 3.6.

• The Hamilton CBD is wholly supplied by Bryce St, Kent St and Claudelands zone substations all of which supply power at the C1 security level.


Figure 3.6 indicates the WEL security levels applied in system design.

Cla

ss Range of Group

Peak Demand (GPD) MVA

Cus

tom

er

Impa

ct

Secu

rity

Leve

l

Con

tinge

nt

Cap

acity

Time to Restore after 1st Interruption

Time to Restore after 2nd Interruption

D 25 to 200MVA: Major Transpower GXP

>10k n-1 100% Maintain 100% of GPD.

Restore 100% in repair time

C1

10 to 25 MVA: CBD zone and switching substations

>2000 n-1 100% Maintain 100% of GPD.


C2

10 to 25 MVA: Small GXP, primary urban zone substations

>5000 n-1 100% Maintain 100% of GPD.

Within three hours restore 90%, repair time 100%

B1 5 to 10 MVA i.e. Secondary urban zone substations

>2000 n 100%

Within 15 minutes restore 75%, within three hours 90%, repair time 100%

Within three hours restore 90%, repair time 100%

B2

2.5 to 5 MVA i.e. Rural zone subs and urban interconnected feeders

>1000 n 80%

Within one hour restore 75%, within three hours 90%, repair time 100%


B3

1 to 2.5 MVA i.e. Urban & rural interconnected feeders

>300 n 67%

Within one hour restore 50%, within three hours 75%, repair time 100%


A

0 to 1 MVA i.e. Rural feeder, urban spur, distribution transformers

<300 n Note 2 Restore 100% in repair time


Figure 3.6 - WEL security criteria applied in system design

Note 1: No interruption at first event (n-1). Note 2: Refer to WEL’s Customer Service Standards for LV Network backup,

dual distribution transformer capacity or temporary supply criteria. [Temporary options include construction of prefabricated OH lines, HV or LV flexible surface jumpers or 300kVA generator supplies]


3.2.4 Network Load Characteristics WEL uses an ICP database to store customer information. Using that database the pie charts, shown below in figure 3.7, were developed. These charts quantify the most common customer types supplied by each zone substation. By using the charts below, in conjunction with the zone supply maps in figures 3.4 and 3.5, it is possible to determine the spread of customer types across the network. There is a relationship between customer type and load characteristic. By combining local knowledge with the information in the pie charts it is possible to ascertain what the load characteristics for different parts of the network are. Performing that analysis confirms that all zones are made up of a high proportion of residential customers. Bryce St and Findlayson Rd have the lowest proportion of residential customers with around 50-60 percent. Zones with the most Agricultural, Forestry and Fishing ICP’s are Weavers, Hamilton 11kV, Gordonton, Findlayson Rd and Horotiu, in that order. Commercial customer categories such as Retail Trade, Accommodation, Cafes and Restaurants, Property and Business Services and Financial and Insurance are most prevalent in Bryce St and Claudelands. This makes sense as these zone substations supply the Hamilton CBD. The Manufacturing sector is best represented in Kent St, Latham Court, Sandwich Rd and to a lesser extent Avalon Dr. Zones with the most Wholesale Trade ICP’s are Latham Court, Kent St and Sandwich Rd.


Bryce St

109286 153

51

41

119

399

29

73

68

1922

118

Electricity - Gas & Water Supply

Retail Trade

Accomodation Cafes & Restaurants

Transport & Storage

Communication Services

Finance & Insurance

Property & Business Services

Education

Health & Community Services

Cultural & Recreational Services

Residential

Other

Avalon Dr

4943

195

8960

42Agriculture-Forestry & Fishing

Manufacturing


Residential

Other

Chartwell

230

6660

13844

40

Agriculture-Forestry & Fishing


Retail Trade

Residential

Other

Figure 3.7 – Load characteristics for zone substations


Claudelands

120

72

43

41

51

5956

23040

5010 225

67

8055

Manufacturing


Retail Trade

Accomodation Cafes & Restaurants

Transport & Storage

Communication Services

Finance & Insurance


Government Admin & Defence

Education



Residential

Other

Findlayson Rd

474

539

79 Agriculture-Forestry & Fishing

Residential

Other

Glasgow St

240

62

12

44

41

1853

185


Retail Trade

Finance & Insurance



Residential

Other



Horotiu

39541

3256


Manufacturing

Residential

Other

Gordonton

552

879

46


Residential

Other

Hamilton 11kV

11449

155

57051

10344

5340

46



Retail Trade


Education



Residential

Other



Kent St

165

40

87

103

182

44

307

42

24

2650

125

Manufacturing

Construction

Wholesale Trade

Retail Trade

Transport & Storage

Finance & Insurance



Personal & other services

Residential

Other

Latham Court

50

53

55

3615

183

40147Manufacturing

Wholesale Trade

Retail Trade

Transport & Storage


Residential

Other

Peacockes

211

43

3841


Transport & Storage

Residential

Other




Te Kauwhata

319

984


Residential

Other

Pukete

86 87

45

1678


Manufacturing

Construction

Residential

Other

Sandwich Rd52

48

88

4931

150

15980

15541

Manufacturing


Construction

Wholesale Trade

Retail Trade

Transport & Storage


Residential

Other


Weavers

832

34

41

2408

157




Residential

Other

Te Uku

347

2355


Residential

Other

Wallace Rd

53641

5120


Retail Trade

Residential

Other



3.2.5 Peak Load and Total Electricity delivered.

The highest peak demand over the 2005/2006 financial year for WEL’s network was 223.5 MW. This figure was derived by summing the total power supplied by Transpower with the embedded network generation export. As such 223.5 MW can be considered to be the peak power consumed by WEL’s customers plus WEL’s network losses. The figure therefore is slightly higher than the peak power received by all customers. The total amount of energy supplied by WEL over the 2005/2006 financial year was 1,102 GWh. This figure was derived by summing the energy supplied by Transpower with the energy supplied from embedded network generation export. The figure therefore includes WEL’s network losses. 3.3 NETWORK CONFIGURATION WEL takes supply from Transpower Grid Exit Points (GXP’s) at Hamilton, Western Road, Meremere and Te Kowhai substations as well as from an embedded 50MVA generation plant which connects to the Pukete zone substation. At Hamilton and at the embedded generation plant, WEL is supplied at both 33kV and 11kV. At Western Road, Meremere and Te Kowhai the supply is at 33kV. Power is distributed from the 33kV GXP’s via 33kV overhead lines or underground cables to 33/11kV zone substations. The Hamilton, Western Road and Te Kowhai 33kV GXP’s are interconnected through WEL’s 33kV system to enable back-feed to Western Road as required. There is no 33kV connection between the Meremere and Western Road systems. The supply to the Hamilton CBD is by underground 33kV feeder-transformer circuits with all underground distribution at 11kV. The 11kV distribution system is an interconnected radial system with 11kV trunk feeders interconnecting and meshing these central zone substations ensuring (n-1) system security. There is redundancy on both the 11kV and LV networks, as is typical of high reliability underground networks serving CBD areas. The 33kV supply to the suburban areas of Hamilton is by a closed 33kV mesh connected system which enhances delivery and reliability and also provides (n-1) security. All zone substations located in Hamilton have two transformer banks and the 11kV distribution is a radial system with interconnection points. In rural areas 33kV sub-transmission is primarily radial with limited interconnection capability through the 11kV system. Both the 33kV sub-transmission and 11kV distribution are mostly of overhead construction except where they traverse the residential areas of Hamilton.


3.4 AGE PROFILES, CONDITION ASSESSMENTS AND CURRENT

MAINTENANCE PRACTICES FOR EACH ASSET CATEGORY This section contains age profile, condition, and maintenance programme and asset value information for each asset category. The asset renewal programme each asset category is detailed in section 6.

3.4.1 Zone Substations The zone substation category includes the buildings, outdoor structures, foundations fences, oil interception equipment and auxiliary equipment such as power supplies, etc, that make up the zone substation but excludes major items of equipment within the zone substation, such as zone transformers and HV circuit breakers which have their own category. Zone substations are used to transform power from the 33 kV transmission voltages to the 11kV distribution voltage. There are 18 zone substations with original construction dates ranging from the 1950’s to 2002. The zone substations are of varying construction types that reflect the design standards at the time of their construction. Buildings have been well maintained and are in reasonable condition with some repairs of leaks and painting required. Security fences and other civil works are in excellent condition. All zone substation equipment items are subject to regular, documented maintenance regimes. Monthly site visits and coincident visual site inspections are carried out. Thermo vision and ultrasonic inspections are carried out on most HV equipment on an annual basis, or when problems are suspected, to detect unusually high levels of temperature or electrical discharges. DC Batteries are replaced at the manufacturers’ recommended periods, even when ostensibly in good condition as a precaution against unexpected failure. All equipment is suitable for its purpose and in a state that is generally aligned to its age. As can be seen in figure in figure 3.8 five zone substations have a capacity utilisation in excess of 60%. Plans have been put in place to address the issues at Peacockes Rd, Horotiu and Wallace Rd. Refer to the Network Development Programme in section 5 and Appendix 2 for details. In the case of Glasgow St there is a strong 11kV backup supply available from Weavers which can pick up 10 MVA. For Finlayson Rd future installation of cooling will raise the continuous capacity to 10 MVA.


Zone substation capacities are as listed in figure 3.8.

Zone Substations Transformers Installed Capacity (MVA)

Firm Capacity N-1 (MVA)

Transformer Emergency Capacity 4 hours (MVA)

Installed Capacity Utilisation

Avalon Dr 2 x 23 MVA 46 23 28 40% Bryce St 2 x 23 MVA 46 23 28 48% Chartwell 2 x 23 MVA 46 23 28 40% Claudelands 2 x 18 MVA 36 18 18 55% Gordonton 2 x 5 MVA 10 5 7.5 58% Horotiu 2 x 10 MVA 20 10 15 67% Kent St 2 x 23 MVA 46 23 23 34% Latham Court 2 x 15 MVA 30 15 15 46% Peacockes Rd 2 x 10 MVA 20 10 15 68% Pukete 11 2 x 15 MVA 30 15 15 34% Sandwich Rd 2 x 23 MVA 46 23 28 45% Te Uku 2 x 5 MVA 10 5 7.5 51% Wallace Rd 2 x 10 MVA 20 10 15 66% Glasgow St 1 x 10 MVA 10 10 Note 1 15 79% Kimihia 1 x 10 MVA 10 2.5 Note 1 12 34% Weavers 2 x 7.5 MVA 15 7.5 11.3 52% Te Kauwhata 2 x 5 MVA 10 5 7.5 50% Finlayson Rd 1 x 7.5 MVA 7.5 3 Note 1 10 67%

Figure 3.8 –Zone Substation Capacities Note 1: N-1 supply is via the 11kV network.

3.4.2 Zone Substation Transformers The zone substation transformers are generally in very good order. Regular inspections and oil tests have been carried out on the zone transformers throughout their life. All zone transformers are fitted with silica gel breathers which are inspected regularly to minimise moisture ingress. Where necessary oil has been dried out and de-acidified. In recent times Dissolved Gas Analysis (DGA) has been carried out by independent specialist parties and this has allowed the internal condition of the transformers to be monitored and trended. This has revealed that the transformers are in a condition appropriate to their age and that there is no evidence of accelerated insulation ageing or deterioration.


The age profile of the zone substation transformers is shown below.

0

1

2

3

4

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40 42 44 46 48 50 52 54 56 58 60 62 64 66 68 70 72 74 76 78

Age (Year)

Qua

ntity

(Nos

)

Figure 3.9 – Zone Substation Transformers – Age Profile Zone transformers are expected to have a life of 60 years. No transformers will exceed the expected life during the 10-year planning period.

3.4.3 33kV Circuit Breakers Circuit breakers are in good condition. All 33kV circuit breakers are regularly maintained on a periodic basis in accordance with recognised maintenance practices. For SF6 and vacuum breakers there is a maximum interval of 2 years between services. This interval is reduced where multiple trippings have occurred or where trippings have involved high fault levels. The programme includes checking at least one breaker from every location for dust accumulation and de-dusting using live line techniques as required, partial discharge tests, gas pressure alarm integrity checks, trip timing checks, trip circuit integrity checks, SCADA alarm, and control checks and contact maintenance according to manufacturer recommendations. For oil circuit breakers the maintenance programme includes partial discharge testing as determined appropriate, contact and turbulator erosion checks, oil change if required, trip timing checks, trip circuit integrity checks, SCADA alarm and control checks.


The age profile of the 33kV circuit breakers is shown in the following graph.

0

10

20

30

40

50

60

70

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40 42 44 46 48 50 52 54 56 58 60 62 64 66 68 70 72 74 76 78

Age (Year)

Qua

ntity

(Nos

)

Figure 3.10 – 33kV Circuit Breaker – Age Profile

3.4.4 11kV Circuit Breakers For 11kV circuit breakers and other 11kV switchgear there is an interval of 2 years between services. This interval is reduced where multiple trippings have occurred or where trippings have involved high fault levels. Periodic inspection and condition monitoring techniques such as partial discharge tests are carried out and the insulation oil in the oil filled circuit breakers is changed at regular intervals. The maintenance programme also includes contact and turbulator erosion checks, trip-timing tests, trip circuit integrity checks, close circuit integrity checks, SCADA alarm and control checks. Except for one substation all 11kV switchboards are in good condition with a significant number having been replaced over the last few years. Routine condition monitoring so far indicates no significant maintenance problems that require switchgear replacement. Many of the remaining older switchgear units are of solid construction. Older items in particular are kept under review through condition monitoring regimes. All switchgear is adequate for the existing and prospective fault levels. Where condition is unsatisfactory or where equipment fault level limits are no longer sufficient, replacement will be arranged.


The age profile of the 11kV switchgear is shown below.

0

10

20

30

40

50

60

70

80

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40 42 44 46 48 50 52 54 56 58 60 62 64 66 68 70 72 74 76 78

Age (Year)

Qua

ntity

(Nos

)

Figure 3.11 – 11kV Circuit Breaker – Age Profile

3.4.5 33kV Sub-Transmission Underground Cables Most of the sub-transmission circuits in the Hamilton city area are underground; paper insulated solid type or gas pressure cables which are comprised of a mixture of aluminium and copper conductors. Three of the circuits have gas pressure cables. These cables are constantly monitored via SCADA for loss of pressure and are visited on a regular basis for physical inspections. Monitoring of the gas cables indicates that presently they are still performing as required. Other sub-transmission cables are PILC or XLPE insulated. No weaknesses have been reported with these cables. The design rating of 33kV cables is a critical factor in the operation of a system. The cables have been modelled using the PCORP software from which maximum allowable current flows for WEL’s loading conditions have been determined. Two circuits, the Bryce Street cables, have been identified as being capacity limited. Alarms are displayed on SCADA to ensure that allowable capacities are not exceeded. The standard type of 33kV cable that has been used recently, and that will be used in the future, is XLPE insulation single core. Conductor cross-sectional areas are selected according to each site requirement. Temperature monitoring systems have been installed on key cables and analysis is ongoing to ensure operational practices are appropriately applied to maintain the cables within a temperature range appropriate to the prevailing environmental factors.


The age profile of the 33kV cables is shown below.

0

5

10

15

20

25

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40 42 44 46 48 50 52 54 56 58 60 62 64 66 68 70 72 74 76 78

Age (Year)

Qua

ntity

(Nos

)

Figure 3.12 – 33kV Sub-transmission UG cable – Age Profile

3.4.6 33kV Overhead Lines In the outer parts of the city and in the outlying areas served by WEL the sub-transmission circuits that were built prior to the last two years are predominantly overhead lines. These were mostly commissioned during the 1960s and 1970s. Existing lines through residential areas are being under-grounded as city development takes place. For new construction and reconstruction work conductor sizes have been rationalised. The overhead lines include a range of conductor types; copper (Cu), all aluminium (AAC), all aluminium alloy (AAAC) and aluminium conductor steel reinforced (ACSR). Maintenance is RCM based and takes cognisance of the meshed nature of the 33kV system. The maintenance programme includes an annual drive-by or walk-by of the network through which the state of the lines is monitored and assessed for appropriate action. In addition, an intermediate six monthly inspection is performed on the spur sections of 33KV line. This work can be undertaken either by drive by, line walk or use of helicopter and camera depending on which is most effective. The objective is to identify obvious defects that might impact on network reliability in the next two years. Thermal imaging techniques are also used. After faults it is common practice to carry out thermal imaging to ensure integrity of the lines. General visual pole inspections are carried out on a periodic basis. In addition, wood poles are inspected using ultrasonic techniques. These latter inspections have


revealed that the bulk of the wood pole population are in acceptable condition for the time being. Deterioration of the wood poles is monitored closely

The graph below shows the age profile based on an actual condition assessment rather than from construction dates as many sections have been rebuilt or there have been spot pole replacements.

0

5

10

15

20

25

30

35

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40 42 44 46 48 50 52 54 56 58 60 62 64 66 68 70 72 74 76 78

Age (Year)

Qua

ntity

(Nos

)

Figure 3.13 – 33kV Overhead Conductors – Age Profile Sections of three wood pole circuits commissioned in the 1950s are nearing the end of their nominal life. Those that are unsound are scheduled for replacement.

3.4.7 Distribution 11kV Underground Cables All of the 11kV cable installed prior to 1976 was PILC and between 1976 and 1990 XLPE in the Hamilton Central area, and predominantly PILC in other areas. Since 1990 most installations have been XLPE. There is no routine maintenance regime as such in place for the 11kV cables. Ad hoc maintenance consists mostly of repair of cables damaged by external sources.


The figure below shows the cable age profile.

0

5

10

15

20

25

30

35

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40 42 44 46 48 50 52 54 56 58 60 62 64 66 68 70 72 74 76 78

Age (Year)

Qua

ntity

(Nos

)

Figure 3.14 – Distribution 11 kV UG Cables – Age Profile

3.4.8 Distribution 11kV Overhead Lines Distribution 11kV overhead lines constitute a major part of the asset base and hence are allocated due attention. Of the 3,178 km of overhead distribution lines, 206km is wood pole construction with the rest being of concrete pole construction. A RCM based maintenance policy with an inspection regime similar to that for the 33kV lines is again employed. Specifically, a drive or walk by of the overhead network is performed each year. In addition 20% of the network is given a detailed condition inspection. This includes poles, cross-arms, DDO’s, air break switches, lines, lightning arrestors and transformers. Defects are noted and high priority ones initiate corrective maintenance actions. Thermal imaging and ultrasound testing is also performed on each of the overhead feeders each year with emphasis on the first protection zone out from the substation. Thermal imaging is also used after major faults to check the integrity of the lines is still intact. The condition of the lines is recorded in the maintenance records database and is regularly analysed. Generally 11kV overhead lines are in satisfactory condition for their required purpose. The wood pole construction lines are again more closely monitored. Refer to section 6.4.7 for the 11kV overhead lines asset replacement programme. Where practical any refurbishment is coordinated with the under grounding plans to avoid unnecessary replacement of overhead lines if they are to be replaced by underground cables in the foreseeable future.


The graph below shows the age profile of these conductors.

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Figure 3.15 – Distribution 11 kV OH Conductors – Age Profile For the concrete pole lines, other than for minor routine maintenance, the overhead distribution systems do not require any significant investment within the planning period.

3.4.9 11kV Switching Stations There are seventeen 11kV switching station installations. The age profile of the units is shown below.

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Figure 3.16 – 11 kV Switching Stations – Age Profile


As part of the RCM philosophy condition monitoring is carried out. This indicates no major electrical or structural problems with these seventeen stations. The 11kV switching station maintenance programme includes monthly visits where building and building security, grounds and fence security are checked and maintained. For switchgear, SCADA equipment and communications equipment regular routine maintenance is carried out as per schedules while buses are inspected ever 10 years and cleaned as required. Maintenance costs are rising; partly due to the reduced availability of maintenance spares for bulk oil circuit breaker trucks and partly due to the more regular maintenance which is now required. The Life Cycle Cost analysis indicates that an economic solution is achieved by retrofitting these trucks with vacuum units and thus substantially reducing the routine servicing costs. This work is planned within the AMP period.

3.4.10 11kV Ring Main Units Because of problems with oil filled Ring Main Units, these are no longer purchased. All new installations are of the SF6 type. Each year 20% of the ring main population are maintained by performing visual inspection and condition reports, earth testing and reporting, vegetation control, oil level checks or SF6 gas pressure checks, ultra sound testing and through fault indicator tests. At the same time checks are made on the operating handles, earthing conductor ratings, tank condition, pitch box leaks, panel steelwork, labels and warning signs. For ring main units over 15 years old oil samples are taken. Where these test results indicate a problem an internal inspection is performed. Finally for ABB ring mains with bus extension units partial discharge testing is carried out and visual inspection of bus boxes is performed. Where degradation has occurred repairs are carried out where possible.


The Ring Main unit age profile is follows.

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Figure 3.17 – 11 kV Ring Main Unit – Age Profile In 2004/2005 a detailed Life Cycle Cost study revealed that the optimum solution was to retire the UK sourced SOKSS units, which are generally about 30 yrs old. This was started in 2005 and has been completed.

3.4.11 11kV Air Break Switch (ABS) The Air Break switch unit age profile is shown below

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Figure 3.18 – 11 kV Air Break Switch (ABS) – Age Profile


Many air break switches have only in-frequent operation; usually associated with network faults. Hence they are quite critical in the performance of a network. RCM studies have been carried out to determine an optimum maintenance regime. Details of the maintenance programme are as follows:

• Five yearly visual inspection and report on condition of: insulators, arc horns / chutes, contacts, handles, earthing conductor rating, steelwork.

• Five yearly earth test and reporting of results.

• Five yearly condition monitoring through thermal vision and ultra sound tests in

the urban area and reporting of results. Automated ABS’s in rural areas also require monitoring.

• Contact and alignment maintenance, exercise, lubricate and adjust using live

line and jumper techniques on a planned maintenance basis driven by condition monitoring.

• Analysis of the switch to see if it can be moved or removed. Is it appropriate

from the points of: position, accessibility, necessity for the switch, network switch ability, reliability, and quick restoration?

• For automated remote operated ABS’s five yearly operational verification of

line recloser SCADA and communications signalling. This involves temporary live line jumpers or bypass or circuit paralleling operations with no loss of supply to customers. Check all controls and analogues back to System Control.

• Testing of Through Fault Indicators (TFI).

With appropriate maintenance most of the units are expected to be utilised to the end of their nominal life, except where their fault level rating is insufficient to meet the growing system fault level.


3.4.12 11kV Reclosers and Sectionalisers

The reclosers and sectionalisers age profile is shown below.

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Figure 3.19 – 11 kV Reclosers and Sectionalisers – Age Profile Reclosers and sectionalisers, whilst not constituting a major asset value, are very influential in governing system performance figures. A large number were installed in 2004 and 2005 to achieve reduced SAIDI minutes. Since then the discrepancy in maintenance efforts between the older and the new units has become apparent. A Life Cycle Cost analysis has been carried out and as a result the remaining older units are to be replaced. The maintenance programme for Sectionalisers and Reclosers is detailed below. Many of the sectionalisers on the network are old and routine testing has been found to have a negative effect on the reliability of their operation. Therefore testing will only be done when there is indication from SCADA or Sentry data that incorrect operation has occurred. All Reclosers are automated with remote SCADA operation and monitoring. Maintenance is programmed and consists of the following activities:

• Five yearly visual inspection and report on condition of: insulators, arc horns /

chutes, contacts, handles, earthing conductor rating, steelwork.

• Five yearly operational verification of line recloser SCADA and communications signalling. This involves temporary live line jumpers or bypass or circuit paralleling operations with no loss of supply to customers. All controls and analogues back to System Control are checked.

• Five yearly earth test, thermal vision, ultra sound tests and reporting of results.


• The removal of the line recloser from service on the Network using live line techniques when maintenance is recommended based on condition monitoring, return to service and re-liven. Workshop based maintenance and testing including:

• Recording all nameplate data and as found conditions.

• All tests required to verify protection trip, close, reclose, lockout

integrity indications and unit is fit for purpose.

• Measure vacuum contact wear.

• Test oil dielectric breakdown.

• Check oil level.

• Test remote digital and analogues signalling and SCADA operations using temporary RTU’s.

• Test power supply battery and charger.

• Check tank and cabinets for cracks, rust and leaks and maintain as

required. Check and clean bushings. Clean and paint tank and cabinets as required.

• Check cyclo operation.

3.4.13 Distribution transformers The population of distribution transformers covers a diverse range of sizes, types and ages. The transformers associated with the 11 kV overhead systems are mostly pole mounted units. Those associated with the 11 kV cabling system are mostly ground mounted. Many distribution transformers run well below their rated values for much of the time, resulting in long lives for the cores and windings. Provided that the tanks and oil are well maintained, the units may be kept in service for up to 55 years. It has been found rare for units to fail because of old age or deterioration. The majority of distribution transformer faults are caused by lightning damage. For the larger pole mounted units lightning arrestors are now specified as standard at the time of installation to reduce this cause of failure. Transformers prior to 1961 that can be economically returned for 20 years further service are reconditioned. A five yearly inspection regime, arranged to coincide with line inspections and earth testing, is currently performed for distribution transformers with the exception of pole mounted distribution transformers under 100kVA. Those transformers are driven to failure or to the point just before they become an environmental or safety hazard at which time they are replaced. For ground based city and industrial distribution transformers the maintenance programme includes:


• Visual inspection and condition reporting every year. This includes verification of earth conductor size and a recommendation on whether to replace on the basis of inadequate fault rating.

• Yearly inspection of padmount transformers to check security, external panel

deterioration or damage, vegetation control, access and to perform cleaning of HV & LV cubicles, thermal image of connections and bus bars.

• Annual inspection of selected industrial ground based transformers and city

distribution substations, thermal imaging inspections of all links, bus bars and connections, maintenance checks on tank and cubicles, dust and clean of equipment and building internals. In addition oil tests are conducted on a condition basis for transformers 750kVA and above.

• Installation and removal of temporary maximum demand indicators (MDI’s) as

required. All CBD distribution transformers are inspected 6 monthly. Inspections are timed to occur at peak load times – midsummer and midwinter. These are performed by using a hand held 3M type thermal hand gun inspection. Where hot spots are found, detailed thermography is undertaken. The age profile of the distribution transformers is shown below.

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Figure 3.20 – Distribution Transformers – Age Profile


3.4.14 LV underground cables

The age profile of the LV cabling is shown below.

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Figure 3.21 – LV Underground Cable – Age Profile Underground LV cabling is exhibiting only a small number of failures, primarily of the paper based types, which can be ascribed to age related causes. Most faults are caused by damage from external factors. There is currently no routine maintenance performed on LV cables but there is replacement of some paper based type cables included in the asset replacement programme. Refer to 6.4.13 for details.

3.4.15 LV Overhead Reticulation LV overhead reticulation is in satisfactory condition. Many of the LV lines are under built on the same poles as the 11kV and hence inspections are carried out at the same time. Maintenance policy is similar to the previously mentioned 11kV policy and is mainly RCM based with an inspection regime from which the asset condition determines the actual maintenance.


The following graph shows the age profile of LV Overhead Reticulation

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Figure 3.22 – LV Overhead Reticulation – Age Profile As for other overhead lines the age profile is based on actual condition assessment rather than from construction dates as many sections have been rebuilt. As part of the replacement program planned for the 11kV overhead lines, the associated LV lines will also be replaced. The remaining lines are below their expected nominal life. Thus, other than for minor routine maintenance, the overhead reticulation system will not require any significant investment within the planning period.

3.4.16 SCADA; Communications and Control Equipment WEL has a fully functional SCADA system comprised of a Master station, data storage systems, alarming and paging systems and load control systems based at the WEL central premises. As well, there are RTU’s at remote stations. Planned maintenance consists of 4 monthly and 12 monthly inspections and tests on all equipment including:

• Visual inspections, dusting, cleaning and minor repairs.

• Operational checks and measurements.

• Testing, calibration checks and adjustments.

• Meter reading and downloading of data.

• Checking and reporting status indications and software error logs.


• Maintenance of database related to the whereabouts, maintenance history and status of all equipment and the filing of test sheets and reports.

Other SCADA indication testing is done in coordination with circuit breaker and protection testing. The age profile of the equipment is shown below.

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Figure 3.23 – SCADA, Communication and Control Equipment – Age Profile

3.4.17 Load Control Equipment There are currently two primary static 33kV injection plants operating at 283 Hertz, with one as a backup that feed the 33kV supplied from Hamilton Substation. A separate 33kV 283 Hz plant feeds the Te Kowhai point of supply. Rotary 11kV plants are used in substations supplied from the Western Road and Bombay 33kV points of supply. Currently a condition driven approach is followed with an annual inspection and test run of plant prior to winter around March / April. This involves visual checks, a test run of plant, signal strength tests and production of reports. Thermal imaging supports this process. Additionally the static plants undergo a condition assessment performed by Enermet.


The age profile of the assets is shown as follows

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Figure 3.24 – Load Control Equipment – Age Profile 3.5 NETWORK ASSET JUSTIFICATION. An ODV valuation was performed for WEL’s network fixed assets as at 31 March 2004. This revealed the Depreciated Replacement Cost (DRC) to be $190.1M and the Optimised Depreciated Replacement Cost (ODRC) to be $189.5M. ODRC is defined as the depreciated value of the minimum system required to provide electricity of sufficient reliability and quality to all consumers, accommodating reasonable load forecasts. DRC is defined as the depreciated value of the replacement cost for the current system. Subtracting the DRC from the ODRC gives an indicator of the extent to which the network is over-designed. For WEL the difference is around $600,000 or 0.3% of the asset base. It is therefore fair to say that WEL a very small amount of over-design on its system. Network items where the optimisation process resulted in an ODRC below DRC are the following:

• Two 33kV sub transmission circuits, Horotiu to Bankiers Rd and Kimihia to Raynors Rd, were judged as being of a higher capacity than that required to meet quality of supply criteria so were optimised from heavy to light resulting in a total DRC reduction of $126,200.

• Glasgow St zone substation land was optimised to 50% of current land value

resulting in a DRC reduction of $35,500. This is due to the large plot size of 4,046 square metres which exceeds the typical requirement of 2000 square metres. The reason for the large size is due to the site being purchased from Transpower who previously run a 110kV substation there.


• Double trenching exists in some CBD areas where cables have been installed at different times. Where appropriate single trenching has been optimised to shared trenching. This has lead to a reduction in DRC of $167,700.

• Four 11kV feeders (CHA CB5, CHA CB6, CRA CB3 and FDL CB2) were

found to be oversized and have been optimised from heavy to medium causing a reduction in DRC of $55,100.

• Eight 11kV ripple injection plants at Avalon Drive, Gordonton, Horotiu, Latham

Court, Peacockes Rd, Wallace Road, Te Uku and Sandwich Rd zone substations were optimised to a single 33kV ripple injection plant resulting in a total DRC reduction of $240,000.

The valuation views all other parts of WEL’s network to be the minimum required to provide the desired quality of supply given reasonable load forecasts. Comments from the report on the suitability of various parts of the network include the following.

• All four Transpower points of supply supplying WEL’s network are required to meet WEL’s quality of supply criteria.

• Load flow studies undertaken show that removal of any sub transmission

circuits would directly lead to security levels and voltage limits being exceeded.

• Optimising out any one zone substation in urban areas would place

unacceptable loadings on the 11kV network. Optimising of rural zone substations would impact directly on voltage levels and require very large 11kV conductors to ensure that the quality of supply criteria is achieved.

• No optimisation of underground cables to overhead lines has been applied

due to local authorities requiring all new work within Hamilton City boundaries to be underground and all new work outside the Hamilton City boundary in urban, rural lifestyle and significant interest areas to be underground.

• Due to the CBD requirement of N-2 security the backup available via the 33kV

and 11kV networks is appropriate and no optimisation is necessary.

• The use of indoor 33kV switchgear installed at Horotiu, Pukete and Sandwich Rd zone substations is in line with current practice for newer, high density, industrial and residential locations where space, visual and pollution impacts are of importance. Therefore no optimisation is performed.

• The majority of 11kV feeder cables and lines are appropriately sized to deliver

WEL’s horizon loads and to maintain the required quality of supply.

• Distribution transformer capacity utilisation is 36.72% which is consistent with the ODV handbook. Therefore no optimisation is required.

• The LV network in the CBD is an interconnected radial system which is

appropriate given the N-2 security requirement. In suburban and rural areas


the LV is radially fed and generally not interconnected. This is also appropriate given the reduced level of security required. The LV system is therefore not viewed as being over designed.


4 SERVICE LEVELS 4.1 CONSUMER PERFORMANCE TARGETS WEL’s goal is to provide a quality product to all consumers. WEL defines quality as “providing a network that is safe, reliable and fit for purpose”. Out of the factors contained within the definition WEL places primary importance on safety. As such safety practices are chosen to be consistent with industry best practice. These are measured using the indicators described below. Reliability is also a critical performance indicator. Appropriate levels of reliability are determined by combining customer survey results with benchmarking studies and by taking implementation costs into account. Quality is measured by the following Safety and Reliability indicators. 4.1.1 Safety

• Target for number of accidents/events and serious harm incidents is zero.

• Lost time injury accident (LTIA) has been used as measure and target is zero for every year. Key controls are:

• Restricted access to dangerous equipment.

• Field staff and contractors using safe work practices.

• Adequate electrical protection systems to cut the power to

potentially dangerous situations.

4.1.2 Reliability Reliability can be measured in a number of ways. WEL uses the following indicators to measure reliability performance.

• Number of interruptions.

• System Average Interruption Duration Index (SAIDI).

• System Average Interruption Frequency Index (SAIFI).

• Customer Average Interruption Duration Index (CAIDI).

• Maximum outage duration for each outage.

• Customer Repeated Interruptions.


The following figures depict the target performances for the current planning year (2006/2007) and the future 10 years. These targets exclude interruptions and faults emanating from Transpower’s system or from the WEL low voltage systems. Faults per 100km

Measure 2006/ 2007

2007/ 2008

2008/ 2009

2009/ 2010

2010/ 2011

2011/ 2012

2012/ 2013

2013/ 2014

2014/ 2015

2015/ 2016

33kV Faults/100km

2.76 1.84 1.23 1.23 1.23 1.23 1.23 1.23 1.23 1.23

11kV Faults/100km

8.74 8.68 8.58 8.37 8.20 8.04 7.84 7.68 7.53 7.35

Figure 4.1 – Faults per 100km Number of Interruptions

Measure 2006/ 2007

2007/ 2008

2008/ 2009

2009/ 2010

2010/ 2011

2011/ 2012

2012/ 2013

2013/ 2014

2014/ 2015

2015/ 2016

WEL Networks unplanned 33kV 9 6 4 4 4 4 4 4 4 4

WEL Networks unplanned 11kV 225 226 226 223 221 219 216 214 212 209

WEL Networks planned 27 27 27 27 27 27 27 27 27 27

Figure 4.2 – Number of Interruptions Refer to section 4.3.2.2 for a description on how Faults per 100km and Number of Interruptions are set. SAIDI, SAIFI and CAIDI.

Measure 2006/ 2007

2007/ 2008

2008/ 2009

2009/ 2010

2010/ 2011

2011/ 2012

2012/ 2013

2013/ 2014

2014/ 2015

2015/ 2016

WEL Networks planned SAIDI 3 3 3 3 3 3 3 3 3 3

WEL Networks unplanned SAIDI 52 47 47 47 47 47 47 47 47 47

WEL Networks planned SAIFI 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03

WEL Networks unplanned SAIFI 1.13 0.97 0.97 0.97 0.97 0.97 0.97 0.97 0.97 0.97

WEL Networks planned CAIDI 100 100 100 100 100 100 100 100 100 100

WEL Networks unplanned CAIDI 46 48 48 48 48 48 48 48 48 48

Figure 4.3 – Reliability indicators Refer to sections 4.3.2.1 and 4.3.1 for a description of how SAIDI, SAIFI and CAIDI targets are set.


Maximum outage duration. As an overall incentive to meet outage duration target levels for urban and rural customers, identified by way of survey, WEL has initiated the WEL Promise with customers, which provides a payment to customers for non-performance. The current standards are:

• urban customers; supply to be restored within three hours.

• rural customers; supply to be restored within six hours. Customer Repeated Interruptions With the changes in the SAIDI reliability targets, it is planned to introduce a new reliability measure, Customer Repeated Interruptions. The customers are currently classified into 6 categories:

1. Central Business District.

2. Industry and Manufacturing.

3. Urban- residential.

4. Urban commercial.

5. Rural.

6. Rural Dairy and Lifestyle.

To simplify the public message it is planned to regroup customers into:

1. Urban – CBD, IND-M, URB-R, URB-C.

2. Rural – RDL, RUR.

This is consistent with the current Customer Promise policy. The plan is to define a minimum standard of service for these customers based on the number of interruptions that they have in a year. In the most recent customer survey, requested information from customers on how many outages were acceptable in any year. Urban customers accepted 2 outages with rural accepting 4 outages. Based on these requests, the following targets have been developed to be achieved by end of March 2011. Please note that faults emanating from the low voltage system are not included in the analysis or the target setting.


Customer Group

Current Performance Strategic Targets by Mar 2011

Urban 87% of customer <=2 per year 90% of customer <=2 per year

Rural 58% of customer <=4 per year 80% of customer <=4 per year Figure 4.4 – Urban/Rural Strategic Targets Last year’s network performance is shown in figure 4.5 below.

Figure 4.5 – Reliability: Customer Repeated Interruptions 2004/05 4.2 OTHER PERFORMANCE TARGETS - ASSET EFFICIENCY,

EFFECTIVENESS AND EFFICIENCY OF BUSINESS ACTIVITY 4.2.1 Operating Efficiency - CPC Cost per customer (CPC) has been chosen as the operating efficiency measure. WEL’s strategic goal is to deliver costs within the best three lines companies in New Zealand. 4.2.2 Asset Efficiency WEL optimises its asset efficiency. Measures used are ODV per customer, ODV per km and capacity utilisation. 28 Lines Company’s data has been used for

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Rural 10% 4% 15% 18% 11% 20% 9% 8% 2% 1% 0% 0% 1% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

Urban 55% 26% 7% 6% 3% 2% 0% 1% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24


benchmarking to understand WEL’s asset efficiency performance in relation to the New Zealand industry. 4.2.3 Low Voltage Complaints WEL records all low voltage complaints (LVC’s). The total number of LVC’s and the details of each are monitored to determine the quality of voltage supplied to customers. There is no specific target for LVC’s, but WEL’s aim is to reduce the quantity and respond to all customer requests promptly. 4.3 JUSTIFICATION FOR TARGET LEVELS OF SERVICE WEL’s objective is to manage the network safely, reliably, efficiently and economically to meet the needs and / or expectations of its consumers. Customer satisfaction is also a primary focus of ISO 9001:2000, the standard WEL has been certified to since 1993. Customer education on service levels and surveys are carried out at regular intervals as required by the company’s need and the Commerce Commission to determine customer’s expectations. WEL has developed its service levels to ensure customer expectations are met or exceeded where economically viable.

4.3.1 Customer Surveys The views and opinions of customers are treated with utmost importance by WEL. Twice yearly seminars are held with major industrial and commercial customers. At those seminars reliability and other issues are discussed, with a specific aim being to educate and discuss the price quality trade-off. Based on those discussions, plans are formulated to ensure the required quality of supply is provided. In addition to the seminars top 10 energy consumers are met with on a regular basis to ascertain their views on supply. All other top 50 energy consumers are visited once a year. For the “Mass Market” one on one communication is not practical. WEL therefore conducts customer surveys to assess views on the price / quality trade off. Three customer surveys have been undertaken in February 2003, October 2003 and October 2004. These customer surveys involved statistically significant numbers of WEL consumers. The first survey was focused on understanding the customer’s satisfaction and future expectations regarding reliability of supply and included:

• What the customer’s current feelings are on reliability of power supply?

• What they want in the future in terms of reliability of supply?


• Whether they are willing to pay more for higher performance or less for lower performance?

The second survey in October 2003 included all the above elements but in addition sought views on what the customer’s cost impact is if the power is off. The third survey in October 2004 again included these elements and also sought views on wider customer service satisfaction issues. A further survey of customers is planned for Oct 2006 in line with the strategy. In future years WEL plans to augment the surveys by conducting consumer seminars. Customers were categorised into six classes: CBD, Industrial and Manufacturing, Urban Commercial, Urban Residential, Rural, dairy & lifestyle (RDL) and Remote Rural. The key points from the customer surveys are summarised as follows:

• 97% of customers rate the WEL present power supply in terms of reliability as acceptable or more than acceptable.

• 86% would prefer to have the present level of reliability at the present prices

maintained.

• 29% on average (up to 44% for rural) wish to see to see further improvement in reliability. However only 5% on average are prepared to pay more.

• 31% on average would prefer fewer outages of a longer duration whilst 36%

on average would prefer more outages of shorter duration.

• 36% on average experience momentary interruptions. 18% on average consider this an inconvenience for them, whilst 9% on average consider this as a major inconvenience for them.

The survey showed that different customers have different priorities and place different emphasis on network performance. Based on the customer survey result, the following assumptions were developed as a valid viable target for WEL.

• The average outage number / customer / year and average duration time from the survey should become the acceptable performance level or CAIFI target.

• If the present performance for any customer group is below that which is

acceptable to that group it should be improved to the level that is considered acceptable to that group.

• If the present performance for any customer group is better than the level that

is acceptable, it should be maintained. I.e. no performance level should be worse in the future than the current level.


Calculated SAIDI from Survey Result (excluding 400V)

Input from survey OutputAcceptable Outage

Number / Customer / Year

Average duration (minutes)

SAIDI (minutes) SAIFI CAIDI

(minutes)

CBD 1 41 0.03 0.00 41.00IND-M 2 34 0.06 0.00 34.00URB-C 1 35 2.27 0.06 35.00URB-R 2 53 34.78 0.66 53.00RDL 3 56 20.50 0.37 56.00Rural 4 77 0.25 0.00 77.00Grand Total 57.89 1.09 52.97

Customer Group

Figure 4.7 – Calculated SAIDI from Survey Result (excluding 400V) Comparison of customer reliability expectations, shown in figure 4.7, with WEL’s strategic performance targets (50 SAIDI minutes, SAIFI of 1 and 50 CAIDI minutes by 2007/2008) shows that WEL’s reliability targets exceed customer expectations.

Another input into reliability target setting is the New Zealand Best Practise Index (NZBPI) for reliability performance. This index recently developed by WEL compares the top quartile performers each year in the areas of SAIDI, CAIDI, and SAIFI. The 2008 network performance targets, shown in figure 4.3, are intended to position WEL in the New Zealand best decile performance category.


4.3.2 Setting Reliability Targets

4.3.2.1 SAIDI, CAIDI and SAIFI. Significant improvements in system reliability have been achieved over the last few years as evidenced from figure 4.8 below.

90

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National Index Actual National Index Forecasting WEL Historical and Target Target

WEL Historical and Target vs NZ National Best Practice Index ( Average of Top 7 excluding First Top 2 )

Figure 4.8 – WEL historical and Target Vs NZBP WEL’s historical performance has dramatically improved from 131 SAIDI minutes 5 year’s ago down to 69.63 SAIDI minutes by end of March 2006. Previously 2008 SAIDI and SAIFI targets of 45 minutes and 0.9 were set. However based on customer feedback and industry benchmarking it has been decided to adjust the 2008 SAIDI and SAIFI targets to 50 minutes and 1.0 respectively.


Figure 4.9 below identifies the proposed plan and the associated costs to achieve this goal.

Figure 4.9 – Reliability Strategic Glide Path and Cost per SAIDI minute WEL has successfully focused on the following strategies.

• Segmentation of customer groups with targeted investment - Major customers and those in the Hamilton CBD are identified. These groups are targeted to ensure that the number of interruptions is at an acceptable level. Where this is not the case network solutions will be implemented to address the specific issues. Investment will also be targeted at those customers with the worst network performance.

• Reducing the number of customers affected when a fault occurs - The strategies WEL employ to deliver these are a continuation of distribution automation projects from previous years. However the network is getting to saturation point for automation. The major focus will therefore be a reduction in the number of customers on large feeders. These projects are capital in nature and will result in a significant increase in capital required for one SAIDI minute saved (See figure 4.9).

• Improving restoration time – Restoration times will be improved by the use of remotely monitored and controlled network components e.g. remote operated switches and ring main units. This will ensure that switching to restore supplies can commence before tradesmen arrive on site to conduct manual switching. This will result in a significant reduction in SAIDI as the majority of supplies are restored remotely.

• Reducing the impact of outages - Undertaking targeted maintenance activities identified through RCM will continue. Experience in other utilities has indicated that this does not contribute directly to reduced maintenance costs. Rather the investment made to ‘maintain’ the current condition of the network

Reliability Strategic Glide Path

66

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will be focused on the components that cause the maximum supply interruption impact. For example maintenance on a component that fails but does not interrupt supply to customers may be reduced. In this way improved performance should be achieved at the same cost;

These improvement initiatives are generally focused on reducing the time it takes to restore supply or reduce the number of affected customers when supply fails. This will mean that the number of faults is not expected to decrease significantly. These reliability strategies will remain in place until the target of 50 SAIDI minutes is achieved. In addition to these reliability strategies WEL is planning to change its approach to maintenance. WEL has the lowest planned outage SAIDI minutes of the New Zealand lines companies. This is an extremely effective yet high cost strategy. When WEL’s overall maintenance spend is evaluated against ODV and compared to other businesses we are in the lower quartile. Much of this performance is due to efficiency e.g. 11kv fault costs have reduced by 20% over the last 2 years. In addition, WEL is increasing the level of expenditure on items requiring planned replacement. These are identified in 5 yearly line patrols, urgent items are then rectified with many identified non urgent items failing before the next 5 yearly review. It is planned to introduce condition grading to these patrols and use the newly commissioned MAXIMO maintenance management system to revisit these sites and increase the level of planned maintenance. 4.3.2.2 Setting Faults per 100km and Number of Interruptions targets.

Twenty eight line companies’ historical data has been used in a WEL study to determine the relationship between controllable failure rate and maintenance cost. Subsequently a curve has been produced which represents this relationship. This has been used for overall controllable failure rate target setting in consideration of the 10 year’s maintenance cost projection. To determine the uncontrollable failure rate, an average of the previous 4 year’s data is used to set the next year’s target. Another input taken into account in the target setting process is the asset replacement programme which has a significant impact on maintaining and improving failure rates. Most of WEL’s 33 sub-transmission systems are meshed. For those that are radial an insulator replacement programme has been undertaken, in the 2005/06 year, to improve security and reliability. This will continue into the 2006/07 year and following years. It is viewed as being reasonable to allow 4 outages for uncontrollable events in the 33KV Radial Networks after March 2008. WEL unplanned 11kV failure rate targets are formulated taking into account the controllable and uncontrollable failure rates determined by the aforementioned process. The Number of Interruptions targets are derived from the relevant failure rate in conjunction with system circuit lengths.


5 NETWORK DEVELOPMENT PLANS WEL has entered into a record level of Capital Expenditure over the next ten years to meet customer needs through growth, security level demand, quality of supply and regulatory requirements. The network processes and capital projects following reflect this customer need and WEL’s business objectives. 5.1 PLANNING CRITERIA AND ASSUMPTIONS. The key criteria and assumptions taken into account during the planning process include:

• Determining future customer needs through changing load patterns, security of supply, reliability and customer surveys.

• Public safety.

• Adequacy of supply capacity to customers.

• Acceptable voltage regulation.

• Appropriate reliability and levels of system security meeting the security

standards as set out in Section 3.

• Correct limitation of the maximum loadings as well as fault ratings applied to network elements.

• Economic loading of circuits and optimal selection of conductors.

• Acceptable system performance under contingent and emergency conditions.

• Territorial Authority District Plan requirements for distribution asset integration.

• Interconnection with adjacent distribution companies.

• Generation in the service area.

5.2 PRIORITISATION METHODOLOGY FOR DEVELOPMENT PROJECTS Throughout the year the network planning section within WEL build up a list of capital projects aimed to address issues of customer needs, security, compliance, reliability, load growth and asset replacement. A process is required which allows all the various types of capital projects to be evaluated, compared and then ranked or prioritised. To prioritise the list of capital projects, WEL uses an investment model. The model evaluates; customer needs, security standard, health and safety compliance, environmental, reliability of supply, security of supply, risk, financial aspects and competitive advantage benefits that may occur as a result of implementing the


project. Each benefit category has a weighting which determines the contribution to the overall evaluation. Compliance and health and safety are given a high weighting. The probability and consequence of risk to compliance, public health and safety and operational health and safety are prime factors in the prioritisation of projects. Projects are also ranked for reliability factors for the expected SAIDI and SAIFI savings. In determining these, historic failure rates, reliability data and feeder lengths are taken into account. The financial aspects of the process uses project costs to evaluate return information to assess NPV, EBIT and other factors achieved by the project. Competitive advantage gained from performing the project is taken into account by making an assessment of improvements to brand, reputation and customer satisfaction. Because of the subjective nature of this assessment, this category has a lower weighting. These projects are scored and prioritised through the investment prioritisation tool. The above process above helps WEL to achieve maximum benefits consistent with company vision and mission statements. See section 2.2. 5.3 DEMAND FORECASTS Demand and load forecasting is required to enable the future configuration of the network to be planned. The objective is to achieve an optimally planned system with staged development to ensure that existing plant and equipment is used effectively throughout the period and to determine any new equipment capacity requirements, either through augmentation or new installation. The forecasting approach adopted is based on a load forecast model which is routinely updated from SCADA data. This includes inputs from; customer surveys, economic indicators, work to be completed in the Waikato area, Territorial Authorities and specific load increases determined through discussions with local industry. The model also allows for inputting of time tagged point loading to test the network and risk of uncertain and unexpected loads or embedded generation on feeders and zones. Embedded generation is treated in two ways; either WEL controllable and thus operationally supportive to demand, or, externally controlled outside WEL control and thus not reliably or continuously supporting demand under contingency. The model determines the energy throughput up to the planning horizon year for each zone substation separately. Present energy throughput is taken and projected forward in each of four sectors: residential, commercial, industrial and farming. The energy forecast is converted to maximum demands by applying historical consumption data and zone substation load factors, and then projected forward. The graph in section 6.3.2 provides the forecast data.


5.3.1 Changing Load Patterns and Demand Side Management

Forecasts take into account the changing load patterns in the residential sector and how they impact on future growth in peak demand. Energy efficient appliances and an increasing use of gas may reduce the rate of growth and are already doing so.

Also of potential significance is the prospect of further changes in the major industries in the WEL service area. Such changes are difficult to predict but are taken into account in future plans as the changes occur.

WEL manages peak demand mainly through ripple injection control of water heating loads. In addition, significant customers are invited to provide interruptible loads which can be used to minimise overall system demand at appropriate times. Embedded generation is also used where available for demand support.

5.3.2 Forecast Loads The after-diversity maximum demand for the winter of 2005 with the Te Rapa Co-Generation plant not in service on the five Grid Exit Points was:

Hamilton 114 MVA

Te Kowhai 58 MVA

Hamilton 11kV 32 MVA

Western Road 33kV 20 MVA

Meremere 33kV 7 MVA Figure 5.1 – Current Loads By the winter 2016 the demand on the existing and proposed Transpower Grid Exit Points will rise to a projected:

Hamilton 119 MVA

Te Kowhai 118 MVA

Hamilton 11kV 37 MVA

Western Road 33kV 35 MVA

Meremere 33kV 9 MVA Figure 5.2 – Forecast Loads

The following graph shows the projected load for the each of the five Grid Exit Points (also referred to as Points of Supply in this section) for the period up to 2016. The graph includes the impact of Te Rapa industrial load when embedded generating plant is not operating. Detailed demand forecasts down to zone substation level are shown in Appendix II.


POINTS OF SUPPLY DIVERSIFIED LOAD IN MVA

(Based on Winter 2005 maximum demand values at TOSP,TE-RAPA co-generator out of service)

131 133 132

140

150 151

160166

173

114 117

98 101 103 106 108 111 113 116 119

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79

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116 118

31 3227 28 30 28 29 31 31 32 32 33 33 34 34 35 35 36 36 37

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1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015

MVA

HAM33 MD (MVA) TWH33 MD (MVA) HAM11 MD (MVA) WES33 MD (MVA) BOM33 MD (MVA)

Figure 5.3 –Point of Supply Forecasting

5.3.3 Grid Exit Points ADMD Accuracy of the Forecast

The accuracy of the projections underlying the forecast is considered adequate for sub-transmission planning purposes. Planning data from the 1996/2005 planning period show a projected 2.45% p.a. peak growth when compared to an actual of approximately 2.95% p.a. excluding the Te Rapa industrial expansion. This lends some confidence to the load forecasting methodology used in the past. The forecast peak loads are subject to variation on account of weather, especially cold weather, and other factors, such as changes in the pattern of water heating controls and any electricity shortage experienced during a winter, which produces abnormal loads. 5.4 GROWTH RELATED NETWORK CONSTRAINTS Potential network constraints that have the effect of restricting substantive load connection within the network have been identified. These include:

• Remote rural industrial load such as quarries and mining, requiring feeder upgrades and/or voltage support.


• Rapid point loading commercial growth beyond expected predictions, requiring network augmentation and new zone capacity installations.

• Rapid loading through residential sub division within new territorial boundaries

for growth beyond expected predictions, requiring network augmentation and new zone capacity installations.

• Reliability of feeder supplies, requiring feeder augmentation or installation of a

new zone sub station.

• Point of Supply (POS) capacity at Western RD and northern network security, requiring installation of a new POS at Huntly 220kV bus.

• Potential POS capacity at Ruakura POS requiring monitoring and options

investigation. Each of these constraints is addressed in the AMP as network augmentation, capacity monitoring and upgrade detailed investigations or non-network solutions as detailed in section 5.7. This is a standard monitoring and ongoing planning process activity. 5.5 DISTRIBUTED GENERATION POLICY Since the Electricity Industry Reform Act 1998 was amended allowing Lines Companies to participate in distributed generation from renewable energy sources, WEL has carried out research into opportunities in the Waikato region and has found that there are future opportunities such as Landfill Gas generation, Municipal Solid Waste Biomass generation, future potential for Wind and Wave generation, Woody Biomass generation and Hydro generation. Some of these options have been investigated, most in detail for their overall benefits and fit to the economic development of the network. WEL’s Network’s Policy for connection of embedded generation is specified in WEL’s Distribution Code and is actively encouraged. WEL takes the view that Distributed Generation is a viable option for network development and for the enhancement of the economic operation of the system. WEL will evaluate Distributed Generation projects on a case by case basis taking into account capacity, cost of transmission, cost of line and reactive power and avoided planned network development costs. Once an embedded generation opportunity is established, the planning and forecast models are updated to reflect this to establish the impact on network development plans. Presently WEL owns an installation at the Horotiu landfill which utilises the gas generated from the decomposition of organic matter to generate power via a gas engine coupled to an l000kVA generator. Initial capacity is 900kW with provision for additional capacity if the quantity of gas permits. WEL is also pursuing a number of wind generation projects.


5.6 NON-NETWORK SOLUTION POLICY WEL manages peak demands by a number of means. The principal method is by shedding water and other storage heating load via the ripple control system. In addition, arrangements have been set up with major customers who can be asked to shed load at critical times. In some cases the communication is by using the ripple control system to send a pre-arranged warning signal. In other cases it is by telephone. Two projects are completed utilising emergency standby generators at customer sites to reduce their demand on the system at critical times. These generators are controllable by remote automatic means. Other potential for distributed generation is actively pursued by WEL where opportunities are presented or recognised. A Te Rapa Industrial customer has an on site 50 MVA co-generator which produces power and heat for the factory processes and power for export to WEL. In the Dairy off season this unit is normally shutdown for maintenance. At times WEL has arranged for the unit to be started up to supply power during the peak period. Innovative means of reducing energy consumption on the WEL system were initiated by the WEL Trust in the 2003, 2004 and 2005 years. These initiatives were to; provide hot water cylinder wraps at subsidised cost to all customers with older homes who requested them, provision of two subsidised compact fluorescent bulbs per customer and provision of subsidised heat pumps to customers who opted to take up the offer. Currently home energy efficiency audits are being offered to low income families which are heavily subsidised by the WEL Trust. 5.7 NETWORK DEVELOPMENT PROGRAMME AND ANALYSIS OF

NETWORK DEVELOPMENT OPTIONS A new Transpower GXP has been built at Te Kowhai some 15 km North West of Hamilton. Commissioning occurred in 2005. Te Kowhai has an installed capacity of 2 x 100MVA 110/33kV transformers to provide 100MVA capacity at (n-1) security. Load has been progressively transferred from the Hamilton GXP to Te Kowhai during 2005/2006 with completion during 2006. As a consequence of the new Te Kowhai GXP the development plans for WEL have in the initial and previous overlapping period of the plan been focused on the requirements for making connections to this GXP and reconfiguring the sub transmission network to optimise balance of the GXP’s loading. These planning activities have taken into consideration the forward requirements for load growth related development impacting on the GXP’s. Airport Zone Sub Station 33/11kV: Hamilton airport and surrounding district is undergoing commercial and industrial growth which will exceed the ability of the 11kV network to satisfactorily supply within permitted design and regulatory limitations.


In considering the requirements to meet the expected growth demand a number of options were considered to achieve the planning and business objectives. Of these; new 11kV feeders, voltage regulators, generation and other non-network solutions were analysed both technically and commercially with the following optimised solution. A new 33/11kV zone substation is required in this area to service the expected load growth. 10MVA transformers transferred from a zone substation upgrade are to be utilised for this application. The zone substation is to be built with radial 33kV supply from the 33kV Peacockes zone bus, but designed for WEL standard dual transformer capacity. Programme Date: Staged 2006/2007/2008 Horsham Downs Zone Substation 33/11kV & Cabling: Hamilton City North Eastern suburbs are zoned and planned to expand into residential and commercial which will exceed the ability of the 11kV network to satisfactorily supply within permitted design and regulatory limitations. In considering the requirements to meet the expected growth demand a number of options were considered to achieve the planning and business objectives. New zone interconnect 11kV feeders, voltage regulators and other non-network solutions were analysed both technically and commercially with the following optimised solution. A new 33/11kV zone substation is required in this area to service the expected load growth and unload rising loads in the Chartwell zone. A WEL standard 2 x 33/11kV 15/23 MVA zone substation installation is planned for this application in the Horsham Downs area. This will also require 11kV underground network augmentation as part of the substation loading regime and unloading from Chartwell Zone Programme Date: Staged 2006/2007/2008 North Western Zone Sub 33/11 & 33kV Cabling: Hamilton City North Western suburbs are zoned and planned to expand into industrial, commercial and residential which will exceed the ability of the 11kV network to satisfactorily supply within permitted design and regulatory limitations. In considering the requirements to meet the greater than expected growth demand a number of options were considered to achieve the planning and business objectives. Of these; new zone interconnect 11kV feeders, generation and other non-network solutions were analysed both technically and commercially with the following optimised solution. This project has been accelerated from the 2009/2010 programme into 2006/2007 due to higher point loading growth than predicted. A new 33/11kV zone substation is required in this area to service the expected load growth and unload rising loads in the adjacent supply zones. A WEL standard 2 x


33/11kV 15/23MVA zone substation upgrade is planned for this application in the area. This will also require 11kV underground network augmentation as part of the substation loading regime and unloading from adjacent zones. Programme Date: Staged 2006/2007 (Accelerated from 2009/2010) Waikato District Health Board, Waikato Hospital Zone Substation: Waikato District Health Board, Waikato Hospital is undergoing site facility growth and increase in demand which exceeds the ability of the 11kV network to satisfactorily supply within permitted design, service standard for this type of load and regulatory limitations. In addition the general area demand through infill and new commercial and medical facilities is introducing network constraints. In considering the requirements to meet the expected growth demand and improved standard of supply a number of options were considered to achieve the planning and business objectives. Generation within this area is being studied to complement the solution. New 11kV parallel feeder augmentation solutions were analysed both technically and commercially with the following optimised solution. A new 33/11kV zone substation adjacent to the WDHB is required for the area to service the expected load growth. The zone substation is to be built with meshed 33kV supply from the 33kV Hamilton bus and designed for WEL standard dual 15/23MVA transformer capacity. This will also require 11kV underground network augmentation as part of the substation loading regime and unloading from adjacent zones. Programme Date: Staged 2006/2007 Spring Hill Zone Sub 33/11 & 33kV Cabling: Hampton Downs area in the northern part of the WEL Network and surrounding district is expanding due to a new corrections facility, refuse disposal and raceway, which will exceed the ability of the 11kV network to satisfactorily supply within permitted design and regulatory limitations. In considering the requirements to meet the expected growth demand a number of options were considered to achieve the planning and business objectives. Of these; new 11kV feeders, voltage regulators, generation and other non-network solutions were analysed both technically and commercially with the following optimised solution. A new 33/11kV zone substation is required in this area to service the expected load growth. A 10MVA transformer transferred from a zone substation upgrade is to be utilised for this application. The zone substation is to be built with single radial 33kV supply from the Meremere / Te Kauwhata 33kV network. Programme Date: Staged 2006/2007/2008


Ngaruawahia 33/11kV Zone Sub Station and 11kV Network Augmentation The Ngaruawahia Township of the WEL Network and surrounding district is currently fed via one main 11kV feeder with high load and constrained back feed capability. A number of regular vehicle impact faults due in the main to long rural feeders within this network are experienced with relatively high SAIDI impact. In considering the requirements to meet the expected growth demand and improve reliability to the area, a number of options were considered to achieve the planning and business objectives. Of these; line upgrades, new 11kV feeders, voltage regulators, additional protection circuit breakers, zone loading upgrades and other non-network solutions were analysed both technically and commercially with the following optimised solution. A new 33/11kV zone substation is required in this area to service the expected load growth and improve reliability. Two 7.5MVA transformers and 11kV switchgear transferred from a zone substation upgrade is to be utilised for this application. The zone substation is to be built with radial 33kV supply from the Te Kowhai / Huntly 33kV network. This will also require 11kV underground network augmentation as part of the substation loading regime and unloading from adjacent zones. Programme Date: Staged 2006/2007 Kimihia Transformer and Switchgear Replacement: Production oriented industrial point load increase in the Kimihia zone has exceeded the zone transformer capacity during 2005/2006. The existing transformer has been upgraded to 10MVA during early 2006 and the associated switchgear is planned to be upgraded during the 2006/2007 period to cater for production requirements and enhance security of supply to essential loads. Programme Date: 2006/2007 Te Kauwhata Zone Substation Transformer Capacity Upgrade: Currently a single 33/11kV 5MVA transformer serves the Te Kauwhata region. In order to service growing load and provide capacity (n-1) security of supply, it is planned to add an additional 33/11kV 5MVA transformer and associated circuit breaker surplus from another project into the existing twin bay of the zone substation. Programme Date: 2006/2007 Raglan Zone Substation: A new 33/11kV zone substation is required in Raglan within the next two years to service the expected load growth and unload rising loads in the adjacent feeder supply areas.


In considering the requirements to meet the expected growth demand a number of options were considered to achieve the planning and business objectives. Of these; new zone interconnect 11kV feeders, voltage regulators, capacitor support and embedded generation solutions were analysed both technically and commercially with the following optimised solution. A new radial 33kV supply and associated switchgear and communications are planned from Te Uku substation to Raglan. This new supply feeder will initially be operated at 11kV via a switching station; with the main zone sub station following within two years. Programme Date: Staged 2006/2007/2008 Huntly New Point of Supply and 33kV Sub Transmission augmentation Huntly Weavers POS has severe Transpower capacity constraints which will not meet the load growth requirements and WEL’s medium term strategy to link Huntly central and northern networks, improve reliability and 33kV sub transmission security through augmentation, meshing and eventual release of the Bombay and Weavers POS’s. In considering the requirements to over come these constraints and expected growth demand a number of options were considered to achieve the planning and business objectives. Of these; new zone interconnect 33kV feeders, voltage regulators, capacitor support, new POS and embedded generation solutions were analysed both technically and commercially with the following optimised solution. A new POS is planned in the 2007/2008 year connecting into the Huntly Power Station Transpower GXP. This will consist of two 220/33kV 60MVA transformers connecting into new 33kV switchgear and interfacing with the existing WEL sub transmission network. In addition new sub transmission feeders will be established between 2008 and 2011 that will provide links in both east and west corridors between Huntly and Te Kauwhata to form a 33kV mesh. Programme Date: Staged 2006/2007/2008 and into 2011. Automation for Improved Reliability A number of automation projects are planned to improve reliability. These include: automation of 11kV air break switches, installation of new reclosers, fusing of 11kV spur lines and SCADA and Communications upgrades. Programme Date: Staged 2006/2007/2008 and ongoing. Peacockes Zone Substation Upgrade: A WEL Networks standard 2 x 33/11kV 15/23MVA transformer upgrade is planned for this substation to accommodate load growth. In addition 33kV bus extension, incorporation of a new circuit breaker and,


communication changes are planned to accommodate the inclusion of the new Airport zone substation. This is planned for 2008/2009. Programme Date: Staged 2007/2008/2010 Wallace Rd Zone Substation Transformer and Cabling Upgrade: A WEL standard 2 x 33/11kV 15/23MVA transformer upgrade is planned for this substation to accommodate load growth. In addition 11kV feeder cables are planned to be upgraded to allow full loading capacity from the station. Communication upgrades will also be carried out during these changes. Programme Date: 2006/2007 Gordonton and Horotiu Zone Substation Upgrades: The WEL standard 2 x 33/11kV 15/23MVA transformer upgrade is planned for both these substations to accommodate load growth. Appropriate communication upgrades will also be carried out during these changes. Programme Date: 2012/2013 Claudelands Zone Substation Upgrades: The WEL standard 2 x 33/11kV 15/23MVA transformer upgrade is planned for this substation to accommodate load growth. In addition 11kV feeder cables are planned to be upgraded to allow full loading capacities from the stations. Appropriate communication upgrades will also be carried out during these changes. Programme Date: 2012/2013 Kent St Zone Substation Upgrades: The WEL standard 2 x 33/11kV 15/23MVA transformer upgrade is planned for both these substations to accommodate load growth. Appropriate communication upgrades will also be carried out during these changes. Programme Date: 2012/2013 Glasgow St Zone Sub Station Glasgow St zone sub station is under consideration for 33kV bus and protection upgrades to improve reliability and security in the area. Programme Date: 2008/2009/2010


Subdivision and Infill Growth Annually around 1500 sections are required to be reticulated to meet customer demand. This requires both network augmentation and in some cases new zone substation as per above development projects. A significant investment is made in this area annually to maintain these new developments. Projects under Investigation for Short Term Consideration WEL’s focus has been on development projects around POS’s, sub transmission, zone sub station and switching stations to ensure robustness, security, reliability, growth and specific customer needs. These issues have been largely addressed and the next level of assets is being considered for development. A number of projects are planned and under final investigation for short term consideration, these include splitting customer numbers per zone and feeder, improvement in network constraint areas, potential compliance issues and high load feeders. These are categorised as:

• Low voltage cabling augmentation for high load growth areas.

• High voltage cabling augmentation for high load growth areas.

• High voltage cabling links for zone interconnection.

• High load zone and feeder balancing.

• Potential compliance issues.

• Customer driven specific projects

Programme Date: Annually. Projects under Investigation for Medium and Long Term Consideration In addition to the short term projects above a number of projects are under investigation for medium term and long term consideration to address issues both customer, potential constraints and observed improvements through planning, these are:

• Low voltage cabling augmentation for high load growth areas.

• High voltage cabling augmentation for high load growth areas.

• High voltage cabling links for zone interconnection and high load balancing.

• Hamilton POS capacity investigation upgrades.

• Hamilton POS 33kV upgrades.


• Line upgrades for capacity and security improvement.

• Protection and security improvements.

• Sub Transmission protection meshing and upgrades.

• Distributed generation opportunities.

• Customer driven specific projects.

Programme Date: Annually and up to 2020. In addition to the above development programs asset replacement programs are in place as described in section 6.0.


5.8 EXPENDITURE PROJECTIONS Figure 5.4 and 5.5 show the Capital Expenditure Projection for the AMP period.

10 Year Capital Expenditure Projection ($000)

Total Network Capital Expenditure 06/07 07/08 08/09 09/10 10/11 11/12 12/13 13/14 14/15 15/16

Asset Replacement *Note 1 4,220 5,177 4,152 5,242 5,833 5,057 5,893 6,202 6,539 7,652

Compliance 1,763 1,154 1,154 1,154 1,154 1,154 1,154 1,154 1,154 1,154

Customer Connections - WEL 8,768 5,359 5,158 3,898 3,898 3,898 3,898 3,898 3,898 3,898

Load Growth Projects 2,967 8,072 4,350 2,745 1,350 2,750 4,150 2,750 2,750 2,750

Security - POS 2,715 6,325 4,250 700 500 1,300 1,700 500 500 500

Reliability 3,801 250 250 250 250 250 250 250 250 250

Undergrounding 1,500 1,200 1,200 1,200 1,200 1,200 1,200 1,200 1,200 1,200

Communication 658 310 488 330 - - - - - -

Total 26,391 27,845 21,002 15,519 14,185 15,609 18,244 15,954 16,290 17,404 Figure 5.4 – Table showing Capital Expenditure Projection for AMP period. *Note 1: Includes capitalised maintenance.


WEL's 10 Year Capital Expenditure Projection

-

5,000

10,000

15,000

20,000

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06/07 07/08 08/09 09/10 10/11 11/12 12/13 13/14 14/15 15/16

$000

Communication

Undergrounging

Reliability

Security - POS

Load Grow th Projects

Customer Connections - WEL

Compliance

Asset Replacement

Figure 5.5 - Graph showing Capital Expenditure Projection for AMP period.


6 LIFECYCLE ASSET MANAGEMENT PLANNING 6.1 MAINTENANCE PLANNING CRITERIA

6.1.1 Drivers and Strategy At WEL maintenance is thought of as a technique to address risks emanating from the ownership of the assets. (The risk management process is addressed in section 8). For the purpose of the policy, the following asset maintenance drivers have been identified as a sub-set of the overall network performance drivers of customer service, reliability and cost effective operation:

• Ensure continued safe operation.

• Improve present network reliability.

• Ensure cost effective maintenance.

• Minimise asset life-cycle costs through optimal planning, design, operation and maintenance, renewal and replacement.

There are a number of maintenance strategy options available. These include:

• Scheduled Periodic maintenance where maintenance occurs at a frequency dependent on manufacturer’s recommendations or company experience;

• Condition based Maintenance is determined by inspections and condition

monitoring techniques; and

• Reliability Centred Maintenance (RCM) Maintenance taking into account plant performance and function rather than the asset itself.

• Fix when failed Do nothing until a failure occurs;

Other maintenance techniques employed to achieve World Class maintenance practice include Root Cause Analysis (RCA) and Failure Mode Effects and Criticality Analysis (FMECA). In practice an optimal balance between the above options is required and this depends on the type of asset, its condition and the consequence of failure.

6.1.2 Optimisation Process At WEL, maintenance is regarded as an insurance premium against the underlying risks associated with the operation of the asset. The aim is to select the type and level of maintenance which results in minimal overall costs, this being the point where


the sum of the maintenance costs and the risk of failure costs are at a minimum while achieving the desired level of network performance. To assist in the objective of maintenance optimisation, a formal Maintenance Optimisation process has been developed.

1.0 Select the equipment and define

system boundary based on criticality

5.0 Develop /update maintenance

standards

2.0 Undertake RCM workshop

Performance requirements

Asset group development

Risk Management

3.0 Identify optimalequipment type

maintenance strategy

Maintenance strategy satisfies

performance requirements

Request to change

maintenance strategy

Maintain process

4.0 Identify optimal consolidated maintenance

strategy

Figure 6.1 – Maintenance Optimisation Process In addition WEL has implemented a Computerised Maintenance Management System (CMMS). This software combined with the formal optimisation process, described above, aims to deliver a maintenance process which is more efficient and effective. Features of CMMS include:

• List of network equipment.

• Criticality assessment of equipment and location.

• List of preventative maintenance tasks and inspections that reflect the maintenance strategy for that class of equipment.

• History of work performed and costs incurred against equipment.

• History of condition assessments obtained from maintenance tasks and

inspections. 6.2 MAINTENANCE PROGRAMME BY ASSET CATEGORY WITH

EXPENDITURE PROJECTIONS

6.2.1 Programme For description of the maintenance programme for each asset category please refer to section 3.4.


6.2.2 Expenditure Projections

Even though more capital is being spent on the network there is no significant decrease in the amount of maintenance that needs to be undertaken. The reasons for this are:

• A significant part of the capital spend in the last few years has been for additional assets. Spending on additional assets will have a corresponding increase in the amount of maintenance required.

• Routine inspections still need to be made on the new equipment. The impact

of an increase in capital is that the next inspection time is pushed out to a full period. This is not always feasible to implement when the inspections are on a route and only a few assets on this are replaced at a time.

• As part of detailed lifecycle analysis it is planned to increase the amount spent

on defect correction to catch up with some under spending in previous years.

• It has also been determined that after the significant capital expenditure in recent times on reliability improvements, a saturation point has been reached and further reliability improvements can be more cost effectively achieved through additional maintenance spending.

The next 10 years total network maintenance expenditure projection including the current year is summarised in the figure 6.2.

Maintenance 10 Year's Average % 06/07 07/08 08/09 09/10 10/11 11/12 12/13 13/14 14/15 15/16

Faults 937 25% 1,173 900 900 900 900 900 900 900 900 900

Relocations 49 1% 49 49 49 49 49 49 49 49 49 49

Distribution Lines 1,486 39% 1,482 1,985 1,770 1,312 1,400 1,400 1,400 1,400 1,400 1,400

Vegetation Management 609 16% 1,000 800 900 500 500 500 500 500 500 500

Zone Substations 623 16% 500 400 500 760 757 603 620 646 743 694

SCADA 89 2% 79 85 85 90 90 90 90 90 90 90

Faults External Subdivision 26 1% 15 15 20 20 25 25 30 30 35 35

Total 3,819 100% 4,298 4,234 4,224 3,631 3,721 3,567 3,589 3,615 3,717 3,668 Figure 6.2 – AMP Period Maintenance Expenditure Projection ($000) The maintenance expenditure profile shown above is broken into the following segments. Faults: Assumption is continuation at current level of activity. Relocations: Assumption is continuation at current level of activity. SCADA and External Subdivision Faults: Increasing over time as the asset base increases.


Vegetation: Expenditure in the next three years is influenced by the recent “Electricity (Hazards from Trees) Regulations” which require a major spend to deal with immediate liabilities. After this time it is expected that the spend will reduce to around the $500k per year level. Zone Substations: Assumption is of a gradual increase. A significant number of new zone substations are planned to be built or extended over the next few years with these assets adding to the maintenance volume. Distribution Maintenance: Assumption is a continuation of expenditure at the current level. An amount of this budget is allocated to the correction of defects. It is anticipated that while the overall level will remain fairly constant the targeting of these will change over time.

WEL's 10 Year Maintenance Spend Profile

0

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1000

1500

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06/07 07/08 08/09 09/10 10/11 11/12 12/13 13/14 14/15 15/16

$000

Faults External SubdivisionSCADAZone SubstationsVegetation ManagementDistribution LinesRelocationsFaults

Figure 6.3 – Maintenance Expenditure Projection for AMP period. 6.3 ASSET RENEWAL POLICY The renewal of aged assets is a key component of the life cycle strategy. Renewal is assumed to consist of replacement and refurbishment activities. Network assets have a finite life and, in order to maintain or improve the level of service provided by the network, system assets must be renewed over the course of time. Expenditure associated with this makes up a significant component of WEL’s overall capital expenditure program. A long term asset renewal strategy has been established with increasing attention being paid to asset replacement management. An asset renewal plan has been developed to ensure the continued high performance of in-service network assets, in particular older assets, through refurbishment and replacement strategies for each class of asset. It identifies the need to continue to renew assets to allow service levels and customer expectations to be met.


Many of the network assets are comprised of separately identifiable items. For example an overhead line typically consists of poles, conductor, crossarms, insulators, etc. Asset refurbishment refers to the separate renewal of these constituent components of the asset and is intended to restore the service life of the asset largely to an ‘as new’ condition. Hence through a process of continual refurbishment, the life of the total asset is extended. Asset replacement comprises the complete replacement of the whole of the asset, which has reached or exceeded its reasonable service life. In the WEL model assets are itemised as identifiable items hence all expenditure on assets is considered to be replacement, rather than refurbishment. The exception to this is zone transformers where refurbishment does take place. The areas that are the focus of a cost effective asset renewal plan and strategies are:

• Asset replacement requirements by age.

• Asset replacement requirements by condition.

• Potential risk to the reliability and security of the network of alternative replacement scenarios.

• The various technical drivers for asset replacement.

• An existing asset database which provides age profiles.

• Condition assessment and monitoring of critical asset types which provides

fault/failure data.

• A policy which defines standard engineering lives and economic working lives of assets.

• Comparison of long-term operating costs (maintenance, spares holdings,

system losses) against capital cost of replacement.

• Assessment of the expected contribution to improvement in network performance.

• Resource and financial ceilings and desirability of smoothing resource

requirements and expenditure on a year on year basis. The decision to undertake to renew an asset is based on age as well the following factors:

• Performance requirements.

• Asset condition monitoring.

• Level of refurbishment, maintenance and operating costs.

• Historical failure statistics.


• A risk assessment associated with deferring asset replacement expenditures. The methodology employed for forecasting future capital resource requirements for the replacement of system assets relies on:

• The age profiles for the various types of assets in the network.

• An estimation of the remaining service life of the assets from expected economic working life or standard engineering life.

• The modern replacement cost of assets.

In order to arrive at an estimate of future asset replacement expenditure, a forecasting model has been populated with existing asset classes, quantities and age profiles. The development of this sophisticated asset economic model has enabled the forecasting of asset replacement costs to a level not previously possible at WEL. As well as the previously mentioned determinants for likely replacement, the risk factors associated with later or earlier than expected replacement are used as modifying factors. A “Risk Limit” is introduced to mitigate the risk of all assets in an asset category reaching the end of their life at the same time; use of the “Risk Limit” factor also avoids over-investment in an asset category. The model allows the calculation of the capital forecast based on three scenarios, these are;

• Age based.

• Age + Condition based.

• Age + Condition + Risk based. The benefits of the asset replacement approach described in this Plan are:

• Provides a consistent, long-term asset replacement strategy which allows real investment requirements to be forecast.

• Results in a reduction in volatility of the total resource (financial and

manpower) requirements year on year.

• Reduces risk of assets failing by avoiding the position where large quantities of assets reach their expected life over a short period of time.

6.4 ASSET RENEWAL PROGRAMME WITH EXPENDITURE PROJECTIONS. The Age Profiles of the assets are shown in section 3. As mentioned previously, the age profiles together with the asset condition surveys are the key determinants of the asset renewal programme.


6.4.1 Zone Substation Transformers

The remaining life of the zone transformers exceeds the 10 year planning period and hence no capital expenditure on replacement is envisaged. One transformer will have reached its half life and an allowance for a “half life” refurbishment has been allowed for in the final year of the 10 year planning period.

6.4.2 33kV Circuit Breakers 33 kV circuit breakers are mostly in good condition. The older oil filled units require greater maintenance efforts than the newer SF6 or vacuum units. In the next financial year it is planned to replace a couple of units that are not capable of accepting the higher fault and load currents anticipated at the Te Uku site and hence these will be retired. Provision has been made to refurbish the mechanisms of one or two of the oil filled circuit breakers mid term. Near the end of the period it is planned to replace two of the older oil filled units which will have reached their economic life.

6.4.3 11kV Circuit Breakers Since service operation has been well below operational limits and maintenance regimes have been efficiently applied, life expectancy is expected to exceed the standard life of 45 years.

It is planned to replace one suite of oil filled 11kV switchgear which has reached its economic life in the forthcoming year. Around 2010 it is planned to replace another switchboard. Near the end of the 10 year period a small number of remaining oil field truck mounted circuit breakers will be replaced with vacuum or SF6 units. Precise timing is dependant upon the results of the regular condition surveys that are being carried out on an ongoing basis.

6.4.4 33kV Sub-Transmission Underground Cables The older 33kV cable circuits are comprised of paper insulated solid type or gas pressure cables with a mixture of aluminium and copper conductors. The constant monitoring by SCADA and regular site inspections of the gas cables indicates that presently they are still performing as required. Hence there are no moves afoot to replace these within the next 10 years.

6.4.5 33kV Overhead Lines (Conductor and Poles) A significant amount of construction of the 33kV overhead network took place in the late 1950’s and early 1960’s. Some of the wood pole lines, although mostly in good condition, are reaching the end of their economic life. This is not only based on the age profile but also on the condition assessment including ultrasonic testing on the poles. It is planned to renew sections of these lines in selected areas. Where viable,


conductor and cross arm replacement will take place at the same time as the poles to reduce overall life cycle costs.

6.4.6 Distribution 11kV Underground Cables Some of the PILC type 11kV underground cables that were installed prior to 1976 are reaching the end of their life as evidenced by a number of sporadic failures. It is planned to commence a replacement program during the planning period beginning with the next financial year. The focus of the programme is likely to be in the older industrial and commercial areas.

6.4.7 Distribution 11kV Overhead Lines As stated in section 3.8.8 generally 11kV overhead lines are mostly in satisfactory condition for their required purpose. Again, the 206km of wood pole construction will require reconditioning within the 10 year planning period. Where practical any refurbishment is coordinated with the under grounding plans to avoid unnecessary replacement of overhead lines if they are to be replaced by underground cables in the foreseeable future. Where overhead wood pole lines are to be replaced with concrete pole lines the conductors will also generally be replaced. Insulator and cross arm replacement is included in this category of asset replacement.

6.4.8 11kV Switching Stations Five switchboards comprising of 54 of 11kV circuit breakers will exceed the normal life expectancy in the planning period to 2016. Provision is made to replace these in an orderly manner; probably one a year from 2010 onwards. The existing 11kV circuit breakers are of the withdrawable oil filled type. The Life Cycle Cost analysis indicates that an economic solution is achieved by retrofitting these trucks with vacuum or SF6 units and thus substantially reducing the routine servicing costs. New switchboards are likely to consist of the fixed pattern types which have reduced maintenance requirements.

6.4.9 11kV Ring Main Units Whilst age is a major factor in replacing assets, it is not the sole determinant. A recent replacement programme was carried out in which a number of UK sourced oil filled SOKSS units were replaced. These were only about 30 yrs old but had developed safety issues which resulted in their early replacement. A number of ABB ring mains with bus extension units have shown evidence of internal discharges. Where significant degradation is discovered the units will be replaced. This has been catered for in the 10 year Asset Refurbishment programme.


6.4.10 11kV Air Break Switch (ABS)

RCM studies have been carried out to determine an optimum maintenance regime. This shows that with appropriate maintenance the units are capable of functioning to the end of their nominal life except that it has been identified that a number of the air break switches will not be able to cope with the rising fault levels in the Network. A programme has been initiated to replace a number each year over the next 10 year budget period. Location is prioritised according to the severity of the circuit rating.

6.4.11 11kV Reclosers and Sectionalisers A large number of reclosers were installed at new locations in 2004 and 2005. These will not require to be replaced within the 10 year period. A smaller number of existing reclosers are of the oil filled hydraulic type which are difficult to coordinate with electronic protection relays at the feeder circuit breakers. When defects arise with these units they are not repaired but replaced with the newer types. Based on past experience, a regular program of replacing one or two units per year is envisaged.

6.4.12 Distribution transformers As previously stated, it has been found rare for units to fail because of old age or deterioration. Provided that the tanks and oil are well maintained, the units may be kept in service for up to 55 years. The majority of distribution transformer faults are caused by lightning damage. Failed units are refurbished to a condition which is better than the state at the time of failure but only if economically viable. That is, if a further 20 years service can be achieved and if the cost of future expected life is less than that of a new unit. The refurbished units are counted toward the asset renewal budget. Allowance has been made in the Asset Replacement Budget to refurbish sufficient units to keep the average remaining economic life of the whole population approximately constant.

6.4.13 LV underground cables Allowance has been made in the Asset Replacement Budget to replace LV cabling of the earlier vintage paper based types that are reaching their nominal design life. This is not a clearly defined age but is evidenced by situations where patterns of faults begin to appear in certain localised areas. As well, there is a programme to replace services pillar boxes of a particular design (concrete/fibrolite) where failures are occurring due to brittle disintegration.

6.4.14 LV Overhead Reticulation Many of the LV lines are under built on the same poles as the 11kV and hence will be replaced at the same time as the associated 11kV lines. Where LV lines are under built to 33kV lines a similar concept applies, but generally there is not a lot of LV under built on 33kV lines. Again adequate allowance has been made to cater for


replacement during the 10 year period which is expected to be of a minor cost; principally because the major cost; i.e. the poles, is allocated to the 11kV budget.

6.4.15 SCADA; Communications and Control Equipment The current central SCADA system has had minor upgrades at regular intervals but because of rapidly changing technology will require a major upgrade within the AMP horizon. Detailed studies of what this involves have been carried out.

The planned operational telecommunications strategy for WEL is to develop the operational telecommunications network by means of utilising existing copper pilot cables in Hamilton CBD, Hamilton East, and Frankton areas with a new UHF digital radio network in the regions beyond Hamilton. Recently installed fibre optic cables along 33kV cable routes will also be used. At each zone substation a sound LAN infrastructure with a minimum capability of 256kbps at each site will be installed to be suitable for the present and expected growth in Control and Internet Protocol devices. This strategy will be implemented over the next four years. Since the primary reason for revamping the SCADA system and associated communications is the rapidly changing technology, this project is not treated as direct Asset Replacement. In addition to the above the pole top network (which provides communication for the rural network remote controlled switching devices) is currently being upgraded to digital radio as new devices are installed. This will continue to be implemented on an ongoing basis. The systems in the older substations are being upgraded as part of an ongoing process. In the immediate future the troublesome existing Sentry system units are being replaced with units suitable for outdoor use so they can be placed at the end of feeder circuits to record outages. The latter project is treated as forming part of the Asset Replacement programme.

6.4.16 Load Control Equipment No major replacement injection plant equipment within the period is envisaged. However field located ripple relays will be replaced as their economic life is reached. There will also be a need for a new 283 Hz injection plant associated with the new Huntly POS. Subsequently ripple relays in the area will also be replaced. That activity is still 2-3 years away and will be incorporated in the Capital Works Budget.


6.4.17 Total Asset Renewal Expenditure Projection.

Figure 6.4 and 6.5 show the total expenditure by Asset Category for the AMP period.

WEL‘s 10 Year Asset Renewal Capital Projection ($000)

(All totals exclude capitalised maintenance)

Asset replacement Category ($000) 06/07 07/08 08/09 09/10 10/11 11/12 12/13 13/14 14/15 15/1611 KV Circuit Breaker 967 0 0 532 84 0 0 0 255

11 KV Ring Main unit 258 200 142 333 240 333 603 369 231 336

11 KV Switching Station 0 0 0 0 0 250 250 250 255

11KV Air Break Switch 255 189 248 298 322 159 203 189 321 345

11KV Reclosers and Sectionalisers 126 117 50 68 170 41 50 41 44 21

33 KV Circuit Breaker 100 0 0 50 50 0 0 96 96

33 KV Overhead Lines 137 322 374 517 518 296 247 527 562 774

33KV Sub-transmission UG cable 0 0 0 0 0 0 0 0 0

Distribution 11 KV OH Lines 562 940 789 1,024 921 561 536 1,274 1,356 1,853

Distribution 11 KV UG cables 200 272 400 326 314 210 158 359 604

Distribution Transformers(11kV / 400V) 190 179 191 321 160 190 200 170 310 111

Load Control Equipment 475 50 50 50 50 50 50 50 50 50

LV Overhead Reticulation 13 22 23 24 23 20 56 56 57

LV Underground cables 147 300 408 600 488 471 315 238 538 907

SCADA Equipment -RTU 103 0 0 7 24 2 3 3 13 20

Zone Substation Transformer 0 0 0 0 0 0 0 0 120

Others 698 232 240 235 642 1,117 1,839 1,511 986 481

Total 2,950 3,810 2,785 3,876 4,466 3,690 4,526 4,836 5,172 6,285 Figure 6.4 - Total Expenditure projection by Asset Category for the AMP Period


WEL's 10 Year Asset Renewal Capital Projection

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LV Underground cables

LV Overhead Reticulation

Load Control Equipment

Distribution Transformers(11kV / 400V)

Distribution 11 KV UG cables

Distribution 11 KV OH Lines

33KV Sub-transmission UG cable

33 KV Overhead Lines


11KV Reclosers and Sectionalisers

11KV Air Break Sw itch

11 KV Sw itching Station

11 KV Ring Main unit


Figure 6.5 – WEL’s 10 Year Asset Renewal Expenditure Projection.


7 Asset Management Systems and Processes 7.1 ASSET MANAGEMENT PROCESSES

7.1.1 High Level Process Interaction The relationship between high level asset management processes is shown in figure 7.1.

Asset Performance

required by owner under cost constraints

AssetStrategyPlanning

AssetGrouping

StandardsDevelopment

AssetLife

Planning

Network Life Plan (made up of ALPs)

to meet performance

requirements for given cost

Network Planning

Data Collection and Validation

Performance Management

Customer Requirements

Maintenance Optimisation

Figure 7.1 – Interaction between high level asset management processes Under each of the master processes are a number of detailed procedures and work method statements, three of which are described in 7.1.2, 7.1.3 and 7.1.4. A description of the main processes shown in figure 7.1 is given below. Asset Strategy Planning

• This process generates and evaluates high-level investment and maintenance strategies, and confirms these strategies with the Asset Owner.


Asset Grouping

• This describes the process, rules and conventions regarding the creation and manipulation of assets into groups for efficiency and other purposes.

Network Planning

• This process develops project plans and optimises them with consideration of cost, performance and risk to produce both the Asset Management Plan and Work Plan.

Standards Development • This describes the process, rules and conventions regarding the standards

required to manage the network. Asset Life Planning

• This process pulls asset data together into cohesive plans for the life of a given asset or group of assets, considers the opex-capex trade-off and combines these into an overall Asset Life Plan.

Data collection and validation

• This describes the process, rules and conventions regarding the definition, capture, storage and validation of asset data.

Maintenance optimisation

• This process develops maintenance plans and optimises them with consideration of cost, performance and risk to produce both the Asset Management Plan and Work Plan.

Asset Strategy Planning, Network Planning, Maintenance optimisation and Asset Life Planning form the core decision making components of Asset Investment Strategy. They reflect the planning process by starting at high level strategies and long-term projections that develop through the planning process to specific detailed plans for short-term activities (example Work plan) and long term plan (AMP). The Asset Life Plans form the backbone of the planning by having a long term view of activities for each asset or asset group and their associated maintenance and capital costs. They are significantly interrelated and changes to any one of these sub-processes will impact the other two. Asset Grouping, Standards Development and Data collection and validation are supporting sub-processes to this planning loop by providing rules and conventions around the asset data and network standards.

7.1.2 Asset Inspections and Network Maintenance The maintenance strategy for each class of equipment is derived as an output of the Maintenance Optimisation process. This uses RCM techniques and other sources of knowledge to develop possible maintenance strategies. The costs and benefits are evaluated to choose the optimal strategy for the particular class of equipment. A consolidation of maintenance strategies occurs for all the equipment classes and an


assessment is made as to whether this will deliver the desired level of network performance and reduction of risk. The equipment maintenance strategy, where it involves periodic maintenance activities or condition assessments, is developed into Job Plans within the CMMS. These specify the maintenance tasks, include estimates of the resource requirements and costs and detail the measurement points for recording condition assessments. The Job Plans are then linked with individual items of equipment and the periods at which the Job Plan is to be executed, in the form of a Preventative Maintenance (PM) task within the CMMS. At the required interval the PM task generates work orders to perform the maintenance activity on the specified equipment. The actual costs and condition assessments are recorded back in the system against the equipment when the work is done.

The aggregation of all these PM tasks effectively defines the routine maintenance works plan.

Root cause analysis and condition assessments may result in the identification of equipment defects that are considered of a high enough risk for corrective actions to be planned. These are then budgeted for and a works program developed to undertake these corrective maintenance actions during the year. Again the actions are set up as work orders in the CMMS against the individual items of equipment and scheduled as required. The work performed and actual costs are recorded against the equipment item.

Faults are managed in a similar way within the CMMS. Work orders are created automatically from a fault call. A more detailed work order structure may be developed in larger fault situations where multiple items of equipment require repair or replacement. Actual costs are recorded against each equipment item and failure codes are recorded. Depending on the nature and consequence of the fault a RCA meeting may be held to identify root causes and initiate corrective actions to prevent future occurrences. These are compulsory for all faults which have a SAIDI impact of > 0.3, any Transpower faults which cause a loss of supply to WEL, any 33kV faults, any defective equipment or human error events.

7.1.3 Network Development Projects The routine monitoring and investigation activities performed by Network Planning staff serve to identify areas of improvement on the network. Those performing the Real Time Operations role and those working in the field are again a good source of ideas for network improvement. WEL has recently implemented CALIB, a software application (see 7.2.7) which allows these and other parties to enter the network development ideas they have. Once an idea for a capital project is entered into CALIB the System Architect performs a high level analysis of technical options and associated benefits and costs. If that process shows the project to have merit the System Architect will develop one or more detailed technical solutions with high level costing. A recommended option is chosen. A technical review is then performed by the Asset Investment Advisor


who checks all technical aspects of assumptions made and the solution proposed. Alterations to the technical solution are made as required. Next Real Time Operations check the recommended solution and assess from an operational perspective whether the proposed solution meets requirements. Any technical aspects which are incorrect or have been overlooked are raised at this point. The process then passes to the Project Managers who review project construction details and determine actual project costs. Implementation issues, if they exist, are raised. Benefit Scoring and Risk Assessment is then performed. This assesses expected financial benefits, compliance, safety and environmental risk mitigation, reliability benefits and competitive advantage gained and produces a score which is used to compare the project merit relative to other projects. Projects are ranked according to score. Given the ranking and the importance of each project an assessment is made on which projects should proceed in the next financial year. Those projects are included in the preliminary Capital Works Budget and will require board approval to proceed. For projects that receive final board approval a detailed project definition document is produced by the Asset Investment Advisor. The project is then passed to the Capital Works Project Managers who use that document to implement the project. 7.1.4 Network Performance Measurement Network reliability affects customers more than any other network performance indicator. As such measurement, recording, monitoring and management of network reliability is given the highest priority. WEL has developed an internal process called “Data collection & validation process for reliability performance data”. This process ensures quality and integrity of data used to calculate HV outage performance figures such as SAIDI, SAIFI and CAIDI. Accurate reliability measurements are critical to the business. They are required to:

• Measure the degree of success in achieving one of the company’s strategic goals.

• Provide the primary customer service performance measure.

• Benchmark our position relative to other network companies.

• Establish our credentials as a party offering asset management services to

other lines companies.

• Disclose all reliability measures required from time to time by any current statute, regulation or other statutory authority.


7.2 KEY ASSET DATA SYSTEMS INCLUDING DATA GAPS AND

IMPROVEMENT INITIATIVES WEL utilises a number of asset management systems to facilitate best practice asset management the most significant of which are described below.

See Glossary of Terms for a definition of acronyms. See later in 7.2 for a description of each application.

7.2.1 GIS (Geographic Information System) The Geographic Information System contains the geospatial information for all WEL’s assets (including some embedded networks) and includes the location of ICP’s. Data contained within GIS includes geographic location of assets, physical and electrical attributes of assets, landbase data which includes property boundaries and owner details, topological maps and aerial photography. GIS is used by field, real-time operations, planning and project management staff within the Operations Division to obtain information on asset location, attributes and connectivity. GIS is an integral component in the group of asset management applications WEL uses. GIS has data links to OMS, ICP and PSS / Adept applications . In the future GIS will also be linked to MAXIMO and DMS. A main focus of the GIS team is to identify and correct information quality issues. As a result there are several data improvement initiatives currently being undertaken. A data collection programme which will complete the conductor size information library is underway. More regular land base updates are now being received. Suspected data errors with low voltage network connectivity are being addressed through an automated query and checking process. The connectivity fix will also address ICP data issues by the transferral of GIS data. Data issues, where they exist, have an impact on all functions performed by the Operations Division. As such there is an incentive to correct errors.

7.2.2 SCADA (Supervisory Control and Data Acquisition) The SCADA system monitors relevant parameters of all significant items of network equipment. The information is brought back to the control centre via WEL’s own pilot wire, fibre or radio communication links and displayed to the system control operators who are able to remotely monitor and control critical equipment. Specific functions performed using SCADA include automatic and manual load control, network switching, fault restoration, real-time system monitoring, retrieval of historic load information for planning, retrieval of relay flag information for fault determination and analysis.


Data held by SCADA includes real-time and historic voltages, current and power levels for significant items of equipment, system configuration information, alarms, operator action logs, equipment ratings and operating instructions. A data gap that currently exists is the absence of some conductor size data which leads to inconsistency of some ratings information. This is being addressed as part of the GIS updates in the 2006/2007 year. Initiatives to improve the current data quality include the commissioning of a Distribution Management System (DMS). This system will replace part of SCADA and will allow equipment searches (not possible with the current SCADA), tagging, addition of notes and will have a direct link to GIS. The direct link to GIS will result in a greater level of detailed information being made available to the operator within one application. Other data improvement initiatives include regular updates from field staff.

7.2.3 OMS (Outage Management System) The Outage Management System was designed to aid in the management, prioritisation and administration of outages on the network. It is used for the capture and recording of reliability data such as SAIDI and is used to assess network performance. An additional feature is provision of lightning information such as strike location, intensity and proximity to the network. Furthermore search functionality contained within the application allows for easy location of specific assets. The main output of the application is an 11 kV feeder tree that describes connectivity and ICP information. Data used by the application to produce this output comes from ICP and GIS. The other data held within OMS is lightning strike information and geographic information which allows the interface with GIS.

7.2.4 Contingency Plan Management System This application stores contingency plans for use in real-time. Contained within the application is a check that compares a list of required CB and ABS statuses with actual statuses in SCADA. If the statuses do not match the plan is indicated as invalid. This flags the operator to modify the contingency plan as required. The data held within the system is basically the contingency plan information. Currently WEL has many of the contingency plans it requires. There is a need however to develop more. This is an ongoing process which is now integrated with our LIFELINES requirement to include co-ordination with other authorities.

7.2.5 ICP (Installation Control Point)


The Installation Control Point database contains all relevant information on all of WEL’s ICP’s. Part of the GIS tracing program also retrieves the number of ICPs on various transformers and populates the information to the OMS database. The ICP database is also used to provide information for the OMS to calculate reliability performance figures. The ICP database is used directly by the OMS and Call Centre applications for their operation. Data stored within the ICP database comes from a variety of sources including the customer, WEL, retailer and electrical inspector. Much of the data transfer between the parties relies on manual processes. There are therefore checks in place to ensure data integrity. WEL has staff dedicated to identifying, investigating and correcting suspect data. This is an ongoing process.

7.2.6 Call Centre Management System The Call Centre Management System records all incoming customer and outgoing dispatch calls. It relies heavily on the Event server in the OMS database for a lot of its operation. The OMS also retrieves information from the GIS on the structure of the network. The OMS as an application relies on the Call Centre and the ICP database for the outage creation / statistical calculations. From time to time data errors such as incorrect ICP information are identified in the field. When this happens investigation is performed and the appropriate changes are made.

7.2.7 Capital Works Library (CALIB) CALIB is a new web based application designed to store all information relevant to the Capital Works Programme. WEL actively encourages employees to identify network issues. CALIB is a tool for capturing those issues, initiating and tracking the workflow required to assess them. The process starts when an employee identifies a network issue and has an idea about how that issue can be rectified. The idea is entered into CALIB. That initiates the creation of a new project and assigns tasks to the various specialists involved in completing the assessment. The work completed, by each specialist, is stored within the database or via links to other documents. This allows for a timely and consistent approach to capital project evaluation, helps to ensure effort is not duplicated and allows all parties to track progress. In summary, CALIB provides a single repository for the network issues people identify and the solutions proposed to address them. Examples of the type of data held within the database include project name, project initiator, project details, budget category, technical options, costing or budget information, links to other files such as excel, word or email, project status, work task completion due dates, persons responsible for tasks.


Reporting functionality within CALIB is being implemented this year. This will improve the ability to complete budgets and view actions required.

7.2.8 PSS Adept This is an application that uses electrical and physical attribute information from GIS to create a load flow model of the network. PSS Adept is used by real time operational staff to assess feasibility of intended actions and also network planning staff in assessing suitability of proposed asset investment. There is also functionality for determination of protection relay settings and fault levels. Data held within the application includes construction dictionary information and geographic, physical and electrical information relating to the network. The quality of the network information relates to the quality of data stored within GIS. The quality of dictionary information relies on regular updates being made. Plans are in place to provide these updates.

7.2.9 MAXIMO WEL utilises a number of large and small information systems for the management of its assets. One of the primary systems is the CMMS (Computerised Maintenance Management System). The CMMS (MAXIMO) was implemented last year going live on October 2005. It provides a primary database of network equipment and locations. It is used to manage all maintenance and capital work on the network through the work orders application and further application modules are used for inventory management and purchasing. For preventative maintenance, a maintenance task is assigned to each equipment item and these then create work orders for the performance of that work at defined intervals. The condition measurements for each item of equipment and the actual costs of the maintenance task are captured. Faults and corrective maintenance tasks generate work orders and again costs, activity and failure codes are recorded against equipment. Capital works involve work orders being created for the construction of each new equipment item with costs being captured against these. The system uses a web browser interface and is deployed throughout the company and selected contractors. The data was sourced from a number of existing systems (primarily GIS) but also existing spreadsheet records and field surveys. The extent to which equipment is defined within the system extends to a lower level and greater detail than has been recorded in the past. Comparison of data against other systems and checking by field inspection is continuing to improve the quality and completeness of data. A new global equipment numbering system has been implemented through use of the system, with each equipment item being given a unique number it retains for its lifetime. For new equipment these numbers are also being physically attached.


7.2.10 DMS (Distributed Management System) DMS enables SCADA to talk to OMS and Call Management applications therefore enabling the creation of outages in OMS and automated calls in the Call Management system. DMS operates over the SCADA database which will in the future enable control and data acquisition of WEL’s network to be conducted via the DMS system.

7.2.11 SQL OLAP and Slice and Dice Slice and Dice is a reporting tool that utilises SQL’s OLAP technology. The ICP, OMS and JDE databases reside on a common SQL server. SQL OLAP is used to extract information from these databases to create cubes for use by the Slice and Dice reporting application. As such Slice and Dice can be used to extract and combine data from various sources for reporting or analysis reasons.

7.3 SYSTEMS DATA FLOW The flow of data between the applications described above is shown in figure 7.2.

Figure 7.2 – Data flow between applications. 7.4 SYSTEM AND DATA OWNERSHIP WEL has adopted the policy of allocating ownership of systems to the primary users of the system (as opposed to the IT department). This fosters a culture of ownership and care and ensures that functionality is in accordance with the users’ requirements. Ownership of the data is also vested in the system owners who are responsible for

Performance Management Reporting (Slice and Dice)

Data Warehouse (SQL OLAP)

GIS OMS

ICP

JDE MAXIMO

DMS SCADAPSS/A CALIB


the accuracy and timeliness collection of the data. To ensure consistency, company wide standards for accuracy and currency are prescribed by the Performance and Quality manager who is also responsible for ensuring appropriate levels of data availability throughout the company. This has led to a significant increase in user satisfaction as determined through regular surveys.


8 RISK MANAGEMENT 8.1 RISK FRAMEWORK WEL recognises risk management to be critical in achievement of its Vision and Mission statements. WEL has a clearly defined Risk Management Policy, which is published on the company Intranet. This Policy and supporting procedure identifies risk management as a core management responsibility and outlines in broad terms the emphasis given to this in both the day-to-day and longer-term facets of managing its assets and overall business. The Policy shows Risk Management to be an integral part of the management (including asset management) and operating structure designed to improve decision-making leading to minimisation of losses and maximisation of opportunities. WEL has developed and maintains a “risk aware” culture with employees empowered and enabled to identify all relevant risks and has in place processes to evaluate, prioritise and manage the risks with the appropriate balance of costs verses consequences and likelihood. This is achieved by systematic application of processes to identify, analyse, evaluate, prioritise, treat and monitor any situations where undesired or unexpected outcomes could be significant or where opportunities could ensue. 8.2 RISK ANALYSIS WEL has adopted a systematic approach to risk analysis. The Quantate Risk Management application, a software based process that is compliant with the New Zealand Standard AS/NZS 4360:1999 Risk Management has been implemented. This ensures a structured approach to the whole process of risk management and has proven to be more efficient and effective than paper based programmes. The application is made up of the following components.

8.2.1 Identifying Risks Operational risks are identified from the bottom up, entered by staff into the database at training sessions, brainstorming sessions or as individuals. Each WEL division is charged with considering Risk Management on at least a monthly basis, incorporating any new risks entered for consideration in their Monthly Reports to the Chief Executive. Strategic risks are identified from the top down and are entered into the database directly by executive managers. Sources of Risk


The software contains categories of generic risk sources to choose from. These categories include:

• Natural events.

• Internal/external human behaviour.

• Technological issues.

• Political/legislative issues.

• Commercial & legal relationships.

• Economic circumstances.

Risks can be identified by location such as:

• WEL House.

• The network as a whole.

• Distinct parts of the network.

8.2.2 Evaluating Risk Each risk is analysed and evaluated by measurement against established criteria to determine the degree of acceptability. The criteria include: Likelihood. History, empirical and/or relevant epidemiological data is considered in determination of likelihood. Consequences. Three categories of risk are considered. They are:

1. Health & Safety - Is there a risk of single or multiple fatalities, serious harm or minor injury?

2. Financial impact - Estimated costs brackets from $ 0 to > $100,000,000 are included.

3. Reputation - Choices of likely effects on WEL’s reputation, from loss of confidence and widespread national condemnation to no significant impact, are given.


8.2.3 Ranking of Risk

In considering each risk, the ‘inherent risk’, (which includes the consequences if no mitigation existed for the risk) is considered first. Any existing procedures or actions that mitigate the likelihood and consequences are then added and the risk is re-evaluated in light of these. This indicates the ‘residual risk’. The larger the ‘gap’ the more effective the mitigation actions are considered to be. However, the importance of this gap depends on where the risk lies on the Risk Acceptability table. Each option in the ranges of consequence descriptors has been given a value according to the potential impact on the business. The scores are calculated in the database and a graph (shown in Figure 18) indicates where the risk lies regarding acceptability. Assumptions made or further explanation as to the rationale for identification of the issue as a risk, are entered in text boxes provided. Provision is made for the employee to indicate the degree of confidence in the information provided so as not to discourage those who believe a risk exists, but may need more qualified or experienced help to determine the real significance of the risk.

Figure 8.1 – Risk Acceptability Chart

8.2.4 Treatment Options Wherever practicable, options to provide improved mitigation are entered. The costs (both initial and ongoing) of the proposed options are estimated. The risk is then re-evaluated and the position of the options is shown relative to the ‘inherent’ risk on the


chart (see Figure 8.1). Once again, the ‘gap’ indicates the effectiveness of the option. 8.2.4.1 Acceptability Benchmarking The Risk Acceptability Chart contains 4 Classes or levels of risk described as follows:

• Class 4 risks are considered intolerable. Risk reduction actions must be applied to reduce the level or consequences of the risk

• Class 3 risks are unacceptable without further controls unless the cost of such

controls outweighs the benefits

• Class 2 risks are tolerable but undesirable. Higher consequences (those further over to the right hand side of the chart) are less desirable. Low cost mitigation may be justified unless the cost of such controls outweighs the benefits

• Class 1 risks are acceptable.

The Risk Acceptability Chart ‘bands’ have been set to reflect WEL’s requirements. These settings were determined once 80 risks had been identified and each one reviewed to establish the potential impact and degree of acceptability to WEL. Decisions were made as to where each risk should sit on the Risk Acceptability Chart. If a risk was clearly acceptable, or if mitigation costs outweighed any advantages that could be accrued through Risk Treatment Options identified, it was used as a benchmark to indicate the class of risk. In this manner, the bands or classes of risk acceptability were adjusted and finalised to reflect WEL’s appetite for risk.

8.2.5 The Risk Management Committee The Risk Management Committee (RMC) comprises a mix of managers including the Chief Executive, GM Operations, GM Corporate services, the Risk and Regulation Manager. The RMC therefore contains a wealth of experience and in-depth knowledge of WEL and the electrical industry as a whole. It is the task of the RMC to review all risks entered in the risk database to validate the data and determine the classification of the risks according to WEL’s appetite for risk. This is accomplished at monthly meetings (more frequently when necessary) to critically review the risks entered. Assumptions are challenged and clarification/additional information sort where necessary to enable accurate evaluation of the risk. Changes are made where required to re-align the risk with the RMC’s judgement and decisions.


8.2.6 Prioritisation Once risks are reviewed, Treatment Action programmes are prepared. Actions required are included in business plans and budgets where necessary. Priorities are set and time frames for actions are agreed with the relevant personnel.

8.2.7 Monitoring The Risk Management application and processes are monitored by the Risk and Regulatory Manager. Monthly reports on the status of planned Action Treatments are prepared for Divisional General Managers and the Chief Executive. 8.3 NETWORK RISK Network risks are identified by real-time and planning staff. This may occur in response to a network event, as part of an investigation or planning study or during the course of routine monitoring. In addition to the software indicated in 7.2 there are other avenues available for reporting the risk. If the risk has been identified from a network event a Root Cause Analysis meeting will be held. There the underlying problem is identified and recommendations for alterations to the maintenance programme and / or capital works programme will be suggested. The recommendations are evaluated by an appropriate specialist and risk mitigation actions and / or strategies developed. The associated cost is also estimated. Periodically the complete list of risk mitigation actions or strategies are compared and subsequently ranked. Those items above a budget cut-off mark will be included in the respective budget. However where the risk identified is assessed as requiring urgent attention current priorities may be reassessed and the action performed without going through the ranking process. In addition to adjustments to maintenance and / or capital programmes, network risks can often be mitigated by the development of a contingency plan. This is the subject of the next topic. 8.4 EMERGENCY RESPONSE AND CONTINGENCY PLANNING The following operational contingency plans are in place: Lifelines. WEL has a comprehensive Civil Defence / Emergency Management Plan that is supported by Network Contingency plans. WEL is involved in Civil Defence through the local Councils. Liaison is initially through the emergency services group of each Council.


Routine Emergency Response. WEL responds regularly to routine emergencies such as network system outages. The methodologies and procedures devised for these are used as the basis for planning of large scale emergencies. Network Contingency Plans. WEL has developed general contingency plans for loss of significant assets or groups of assets. Further development of specific plans for zone substations and critical 33kV circuits is ongoing. Transpower WEL and Transpower interact on an operational basis as below:

• Planned releases of equipment (both for Transpower and for WEL sourced requests).

• Unplanned releases of equipment & restoration of supply.

• Co-ordination and impact.

• Liaison with Civil Defence authorities.

Automatic Load Shedding WEL is contracted to provide automatic load shedding of up to 20% of its total load under certain frequency conditions. The same circuits would also be utilised as the first stage of manual load shedding. Alternative Control Centre WEL operates its control centre from WEL house. When this is not available for whatever reason, there is a standby facility located at the Bryce Street zone substation from which SCADA and control operation can be carried out. A simulated emergency exercise was carried out in late 2003 which demonstrated that the stand-by facility is fully functional and available on an immediate basis when required. Emergency Exercises Regular full scale simulated emergency exercises are carried out to test the emergency procedures and methodologies and determine scope for improvement. Typically these have involved full scale alarms being initiated with only a selection of staff having knowledge of the timing of the exercise.


9 PERFORMANCE EVALUATION 9.1 CAPITAL EXPENDITURE Actual capital expenditure for the 2005/2006 financial year compared very closely with the value forecast in the 2005 AMP. The difference was 2.7%. Figure 9.1 gives the reasons for key differences.

Forecasted Capital Expenditure in 2005 AMP ~ Actual Spend for the Period from April 2005 to March 2006

Total Network Capital Expenditure

2005 AMP Indicated ($000)

05/06 Actual ($000)

Variance Comments

Asset Replacement 3,616 3,969 353

More faults than expected. Replacement cost from faults has increased $314k.

Compliance 1,154 1,694 541 $576k increases from relocation requirements.

Customer Connections – WEL

5,600 6,563 963 $1.3 m increase from new connections.

Load Growth Projects 1,340 1,544 204 Labour and material cost

increased significantly. Security - POS 7,331 7,197 (134)

Reliability 4,502 2,556 (1,946)

$2.2 m project has been delayed into next financial year with 33KV insulator replacement programme to improve security and reliability.

Undergrounding 1,400 857 (543)Original undergrounding indicated has not received final confirmation from Waikato District Council.

Communication 290 177 (113)Resource consent hold-ups have pushed this into next financial year.

Total 25,233 24,556 (677) Figure 9.1 – Forecasted Capital Expenditure in 2005 AMP – Actual Spend April 2005 to March 2006

9.1.1 Gap Analysis and Improvement Initiatives. It is critical to scope the projects in more detail to reduce the variance between AMP indicated capital expenditure and actual spending. The following key initiatives have been implemented during this report year:


Process redesign and implementation: • The network planning process is a core business process for asset

management. At the same time, asset strategy planning, standard development, data collection and validation, asset life planning and asset grouping processes have been implemented.

System implementation. • One way to improve the effectiveness and efficiency of a process is to

automate the process and maintain the relevant information in a central database. The Capital Project Library management system (CALIB) has been implemented to support the network planning process. One of the features is the use of a standard template to produce project scope documents for budget approval.

The following key initiatives are planned for implementation during the Apr 2006 -March 2007 year:

• Specific KPI’s for network planners regarding quality and project scope have been set up as part of the performance management system.

• The GIS data collection project will ensure quality data is available in GIS for

network planning, project delivery and operations.

• System and tools enhancement including GIS enhancement such as data transferability from GIS to MAXIMO and batch tracing, PSS/ADEPT 11KV model development and Geomedia support.


9.2 NETWORK DEVELOPMENT PROGRAMME Figures 9.2, 9.3 and 9.4 show the physical progress of 2005/2006 capital projects with an associated description.

Completed Capital Projects % completed

ABS replacement 100%

Concrete LV Service Pillars replacement 100%

Fin CB and transformer replacement 100%

Poles replacement 100%

Fusing of Spur Lines 100%

HAM substation 11KV load control plant replacement 100%

WALCB4 automation 100%

Hamilton EAST Reliability of Supply Enhancement 100%

Te Kowhai POS - Stage 1 100%

Security Alarms - door switches replacement 100%

TE KOWHAI Village undergrounding 100%

Install TFI on chosen cable circuits 100%

Figure 9.2 – Completed Capital Projects


Capital Projects in Progress as at 31-Mar-06

Project description %

completed

Comments

Load control relays replacement* 90%

Progressing very well. Inaccurate data from ICP database has impact on the final delivery. Money has been carried over to next year.

Chartwell transformer upgrade 10%

Transformers did not arrive on time due to increased material lead time. Money has been carried over to next year.

Te Kowhai POS - Stage 2 80%

The 3 cable circuits have all been installed to program but delays with 33kV switchgear delivery have delayed the overall project.

TA Relocations 159% More requirements than budget.

Undergrounding programme 89% Mostly completed. Original indication from local council

has not received final confirmation.

Reinsulation of Raglan 33KV line and 33KV line from Findlayson Rd to Meremere

65%

This will improve the security and reliability of identified Radial Networks. Delay of work was due to weather conditions and contract cancellation. Money has been carried over to next year.

Figure 9.3 – Capital Projects in Progress

Cancelled Capital Projects % completed Comments

Raglan 11 KV network solution 10%

Delayed till next year. Replaced by re-insulation of Raglan 33kV line and 33kV line from Finlayson Rd to Meremere which will have an improvement of security and reliability.

Avalon CB1 RMU automation 0% Cancelled due to scope change and new benefit and cost analysis result

CHACB13 auto switching of RMU's &TFI 0% Cancelled due to scope change and new

benefit and cost analysis result

Norton Rd 11kV Feeder 5% There have been additional costs caused by Hamilton City Council road changes. This has made the project no longer viable.

Figure 9.4 – Cancelled Capital Projects

9.2.1 Gap Analysis and Improvement Initiatives It is critical for projects to be scoped at a level of detail sufficient to enable project delivery to proceed efficiently. It is also important that current processes be streamlined or modified to reduce the barriers project managers face. This will help to ensure projects are completed on time, within budget, to the required quality standards and safely. Improvement initiatives relating to project scope detail are


discussed in 9.1.1. Those relating specifically to the project management process are described below.

The following key initiatives have been implemented:

Process redesign and implementation • The Capital Project Close Out report template has been reviewed. It

incorporates requirements from different business units. For example, material management, data management, financial information, commissioning reports, completion certification, document control, etc.

Reporting • Timely and quality reports have been set up automatically for project

managers to more easily gauge the financial situation. This reduces duplication and mistakes.

Specific KPI’s • KPI’s have been established for project managers regarding completion on

quality, on time and within budget. These are assessed regularly during performance reviews.

The following key initiatives will be implemented in the Apr 2006 – March 2007 year:

• Continuation of the successful initiatives listed above.

• Small capital works to be performed by the internal work force.

• Major capital works projects, taking place over 3-5 years, to be packaged and assigned to specific contractors.

9.3 MAINTENANCE EXPENDITURE Actual versus budgeted maintenance expenditure for the 2005/2006 year is included in the figure 9.5.

Budget Actual Variance

Distribution Lines $ 1,165,188 $ 906,199 $ (258,989)

Zone Substations $ 321,324 $ 434,116 $ 112,792

Vegetation $ 1,300,000 $ 1,016,955 $ (283,045)

SCADA $ 79,164 $ 96,680 $ 17,516

Faults - Reactive $ 888,000 $ 1,414,151 $ 526,151

$ 3,753,676 $ 3,868,101 $114,425 Figure 9.5 – 2005/06 Maintenance Expenditure- Actual versus budget.


A discussion on the reasons for variation from budget is included below: For zone substations there have been increased costs due to a failure of an interconnecting cable in a zone substation and greater than expected costs with the refurbishment of zone transformers. These refurbishments have come earlier than anticipated due to a revised capital work programme. With Distribution Lines a significantly greater amount of budget was allocated to defect correction. Introduction of the CMMS changed the way some work was categorised to the faults budget. The vegetation budget was decreased to compensate for the over expenditure in the faults budget. For SCADA there were increased costs due to the need to change protection settings in most reclosers and the further introduction of DNP communications. The faults expenditure continued to be greater than the amount budgeted as in previous years. This is due to contributions from a greater than anticipated number of fault calls, introduction of CMMS and a more detailed coding of maintenance and capital expenditure. This latter point has resulted in more cost being coded to maintenance. There was also some cost transfer between the distribution lines and faults budgets. WEL has undertaken several maintenance initiatives over the last financial year. These and future initiatives are highlighted below.

• Continuing failures of two part 33kV porcelain insulators resulted in capital projects being undertaken to replace all these insulators on two critical circuits.

• In the Sandwich Rd area problems with connections failing under fault

conditions resulted in actions to replace these with a more reliable type on the main lines. This has significantly improved reliability in the area.

• Thermal imaging of overhead circuits continues to be an effective way of

identifying potential failure points.

Additional cost has been incurred in the 2005/2006 year and the 2006/2007 year because of Telecoms program to replace all larch and softwood poles in the Hamilton area. Where WEL has circuits on these pole we are replacing cross arms and transferring services at WEL’s cost. In the 2006/2007 year additional budget has been provided in the defect correction area. This will target the removal of line tap connectors on overhead circuits, the replacement of failing binders on a 33kV overhead circuit, replacement of kidney insulators, the completion of a factory modification program for Nulec reclosers and the change to a delta conductor configuration on a number of rural circuits


9.4 SERVICE LEVELS AND ASSET PERFORMANCE

9.4.1 Safety

• There were no reported accidents or events causing serious harm for the year 1 April 2005 to 31 March 2006.

• There were no lost time accidents reported for the year 1 April 2005 to 31

March 2006.

9.4.2 Reliability

• WEL’s performance for the year 1 April 2005 to 31 March 2006 compared to target is as follows.

Performance Measures Target 2005/2006 Actual 2005/2006 Variance

WEL Networks unplanned 33kV 4 19 15

WEL Networks unplanned 11kV 251 237 (14)

WEL Networks planned 30 18 (12)

Total interruptions - unplanned 255 256 1

WEL Networks planned SAIDI 4.00 2.12 (1.88)

WEL Networks unplanned SAIDI 61.00 67.51 6.51

WEL Networks planned SAIFI 0.05 0.01 (0.04)

WEL Networks unplanned SAIFI 1.31 1.52 0.21

WEL Networks planned CAIDI 80.00 171.75 91.75

WEL Networks unplanned CAIDI 46.50 44.41 (2.09)

WEL Networks Total SAIDI 65.00 69.63 4.63

WEL Networks Total SAIFI 1.36 1.53 0.17

WEL Networks Total CAIDI 47.73 45.44 (2.29)

33kV Faults/100km 1.16 5.83 4.67

11kV Faults/100km 9.56 9.55 (0.01) Figure 9.6 – Performance Measures

Actual CAIDI performance was 2.29 minutes better than the target of 47.73. Although the actual SAIDI performance was 4.63 minutes worse than the target of 65 the


reliability performance has improved dramatically from 148 SAIDI minutes in 1998 to 69.63 in 2005/2006. Network performance has stabilised compared to the improving downward trend that was obtained in previous years. Whilst the trend is still downwards it is apparent that this is slowing as the network is approaching its inherent performance capability as determined by the network design and the external environment. Network performance in 2005/2006 was impacted by an increase in road traffic accidents affecting WEL’s assets. Nearly one third of total SAIDI for this year was as a result of these accidents. Figure 9.7 shows outage statistics for April 2005 – March 2006.

Outage statistics for April 2005 - March 2006

Cause Category Outage Number SAIDI SAIDI (%) SAIFI CAIDI

Vehicle Accidents 36 19.58 28% 0.31 63

Defective Equipment 69 14.97 21% 0.37 40

Insulators and Discs 40 8.28 12% 0.16 52

Adverse Weather 31 6.26 9% 0.16 39

Vegetative Debris 5 3.24 5% 0.06 51

Birds 33 2.78 4% 0.15 19

Poles and Crossarms 9 2.43 3% 0.03 94

Broken Lines 17 2.27 3% 0.02 96

Human Element 11 2.03 3% 0.09 24

Planned Shutdowns 14 1.85 3% 0.01 209

High Load 1 1.77 3% 0.01 143

Cable Faults 17 1.42 2% 0.05 31

Trees 6 1.12 2% 0.03 37

Lightning 8 1.12 2% 0.03 39

Possums 12 0.52 1% 0.05 11

Foreign Interference 1 0.00 0% 0.00 31

Grand Total 310 69.63 100% 1.53 45 Figure 9.7 – Outage Statistics for 2005 / 2006 Financial Year

9.4.3 Low Voltage Complaints • The number of low voltage complaints received and the number proven are

reported monthly for comparison with previous year’s data. Figure 9.8 shows the comparison between 2005/2006 year and 2004/2005 year. It shows a 50%


drop of LVC’s that have been proven to be WEL’s responsibility. In total, it shows an overall 26% improvement on LVC’s.

Year Ending Proven WEL

Proven Customer

Not Proven Total

March 2005 18 15 1 34

March 2006 9 16 0 25

Improvement rate (%)

50% 26%

Figure 9.8 – Low Voltage Complaints The majority of voltage complaints have arisen in rural locations. The increase in the number of voltage complaints is principally due to the large number of lifestyle blocks that were subdivided off farms in the area surrounding Hamilton city. This has caused extra loads on lines originally installed to service farms.

9.4.4 Gap Analysis and Improvement Initiatives Analysing WEL’s performance against targets in the service levels and asset performance categories has revealed the following. Overall CAIDI performance has improved significantly. This is due to a number of automation projects and the subsequent improvement in switching operation. Further improvements can be achieved with a shortened response time in the field. This requires additional field resource. These resources are currently being recruited. 33kV insulator failures have contributed to around 12% of the annual SAIDI minute total. As discussed earlier in this document WEL is currently undertaking a number of insulator replacement projects. Completing these projects on time and in accordance with quality standards will result in short and medium term reliability benefits. Reducing the customer numbers affected when an outage occurs has been a significant focus of recent year’s works’ programmes. Ensuring that the reliability distribution automation projects are completed on time and to quality standards is critical to WEL achieving the expected benefits from those projects. Ensuring WEL has ownership of protection settings from determining the philosophy right through to field implementation, including data validation, is critical to WEL achieving the expected benefits from reliability projects. Ongoing review of existing protection settings is critical for safe and reliable network operation. The failure modes of assets have been reviewed and our maintenance strategies re-assessed. Furthermore the capture of fault information is being modified to better


identify the asset type, failure mode and root cause. These measures will allow an accurate assessment of underlying causes and enable the development of the best solutions to these problems. Ongoing Root Cause Analysis (RCA) of significant events identifies new failure modes and risks. This information can be used immediately to identify where maintenance practices can be improved to prevent re-occurrences. In the longer term the population of data in WEL’s Computerised Maintenance Management System (CMMS) will provide information that will allow us to continually improve asset replacement and maintenance strategies. This will have the effect of improving reliability and lowering costs.


Appendix 1 – Glossary of Terms The following represents a list of terms encountered in the text and the associated meanings.

Term Meaning Annual Business Plan

The WEL plan consolidating objectives and financial expenditure for a given financial year.

Best Practice A practice identified through international Benchmark Studies to give the most cost-effective improvement in asset management or other core business performance.

Division A WEL division or section under the control of an executive manager.

CAIDI Customer Average Interruption Duration Index is the average total duration of interruption per interrupted customer.

CBD Central Business District CMMS Computerised Maintenance Management System Connection and Disconnection

Connection/disconnection of service mains to or from overhead or underground LV networks including the removal, reinstatement or installation of neutrals.

Consumer Refer to Electricity Act 1992. WEL use the term Customer. Refer to the definition of Customer. See also definition of User.

Continual Improvement

Recurring activity to increase the ability to fulfil requirements.

CPC Cost per customer – Internal measure of asset efficiency. Customer The end user or beneficiary or purchaser of a product or

service, either internal or external to the organisation. Defect Substandard workmanship, product or service resulting in

the non-fulfilment of intended usage requirements. Distribution Line [Ref NZECP 34] Means works that are owned by WEL used

for the conveyance of electricity to one or more electrical installations.

DMS Distribution Management System, a geographical operator interface updated from SCADA and based on the GIS database, used to manage the distribution system.

Equipment Electrical apparatus, distribution or sub-transmission circuits or plant that forms part of the network. Equipment. Used with the same meaning as “Fittings” as defined in the Electricity Act 1992.

Field The location where the work is being carried out. Fixed Asset A purchase of >$200 with an intended life cycle of > 1 year. GIS The Geographic Information System used for electronic

mapping of the Network. Grid Exit Point (GXP)

The point at which WEL Equipment is deemed to connect to the Trans Power Grid System. The term is interchangeable with POS.

GPD Group Peak Demand High Voltage (HV) Any voltage exceeding 1000 V a.c. or 1500 V d.c. but

usually pertaining to the 11kV or 33kV distribution system.


ICP Installation Control Point. A number that uniquely identifies each connection to an electrical lines network that is recorded in a national registry.

Inherent Risk The level of risk that exists before any risk treatment measures or controls have been implemented.

Inspection Activities such as measuring, examining, testing and gauging characteristics of a product or service.

JDE The J.D. Edwards OneWorld business data system. Key Performance Indicator

A standard unit of measure used to enable comparative analysis between organisations or within an organisation.

Lines The LV and HV network of overhead and underground electricity conductors and cables and their associated equipment such as insulators, poles crossarms etc.

LVC’s Low Voltage Complaints – from customers. These are investigated by WEL.

Low Voltage (LV) Any voltage exceeding 32 V a.c. or 115 V d.c. but not exceeding 1000 V a.c. or 1500 V d.c.

N-1 security A load is said to have N-1 security if for the loss of any one item of equipment supply to that load is not interrupted or can be restored in the time taken to switch to alternate supplies.

Network Utility reticulation system or asset owned by the utility Company, Trust or other body having control and/or ownership in the utility reticulation system including the land, buildings, installations, individual customer connections up to the point of supply, and other improvements on or under which the utility reticulation system is located.

ODV Optimised Deprival Value OMS WEL’s computerised Outage Management System. Operator The SYSCON system controller in charge of the operation. Ownership Boundary

The boundary between the Equipment owned by WEL and the Equipment owned by the Customer. See also Point of Demarcation.

Point of Connection

The point at which a Customer’s Equipment is deemed to connect to the Distribution System.

Point of Demarcation

The point at which a Customer assumes authorised control and maintenance of his system.

Point of Supply [POS]

In this document is defined as the point at which WEL Equipment is deemed to connect to the Trans Power Grid System. The term is interchangeable with GXP.

Quality The totality of features and characteristics of a product or service that bear on its ability to satisfy stated or implied needs, i.e. “fitness for purpose for intended use”.

Quality & Safety Procedures

Detailed description of process activities, records and applicable specifications.

Quality Management System (QMS)

The organisation structure, responsibilities, methods and resources for meeting quality and safety objectives.

RCM Reliability Centred Maintenance – Type of maintenance strategy.

Reliability The ability of an item to perform a required function under stated conditions for a stated period of time.


Residual risk The remaining level of risk after risk treatment measures have been taken.

Retailer An electrical energy supplier who has a User Supply Agreement with WEL Networks.

Risk the probability (likelihood) and consequences, positive or negative, of an event. In some situations, risk is a deviation from the expected.

Risk Management AS/NZS 4360 defines risk management as a term applied to a logical and systematic method of identifying, analysing, evaluating, treating, monitoring and communicating risk associated with any activity, function or process in a way that enables maximisation of benefits or minimisation of losses or detrimental effects.

RMC The Risk Management Committee comprising duly appointed managers responsible for review of WEL’s risk management process.

RMD The Risk Management Database located on InGrid, the WEL Intranet. This is the software application used to record and assist with analysis and management of risk.

RTAP The Risk Treatment Action Programme function that specifies what additional action is required, by whom and by when, to further mitigate a risk.

RTU Remote Terminal Unit – Communications device used for relaying data from the field.

SAIDI System Average Interruption Duration Index is the average total duration of interruption per connected customer.

SAIFI System Average Interruption Frequency Index is the average number of interruptions per connected customers.

SCADA WEL’s computerised System Control And Data Acquisition System being the primary tool for monitoring and controlling access and switching operations for WEL’s Network.

SR-EI The Safety Rules Electricity Industry July 2000 Stakeholder People and organisations who may affect, be affected by, or

perceive themselves to be affected by, a decision or activity. Standard The document that prescribes the requirements with which

the produce or service has to conform. The criteria for acceptable levels of safety performance/behaviours set by WEL Networks, industry codes or relevant legislation.

Standard Operating Procedure

A locally controlled work method statement or ‘desk top’ file.

Strategic Risk A risk that could threaten the viability of the business, or would grab the attention of stakeholders resulting in serious reputation consequences or impact significantly on the balance sheet.

Supplier Organisation that provides a service or product to the customer: − in a contractual situation the supplier may be called the

contractor − the supplier may be the producer, distributor, importer,

assembler or service organisation − the supplier can be internal or external to the


organisation. SYSCON The WEL Networks Ltd network system control centre and

the network system controllers. Territorial Authority (T/A)

The controlling authority having control and responsibility for roads and road reserves.

Test Permit The permit for access to HV equipment which has been removed from service to enable testing and where procedures are required to control hazards created by the testing.

Transpower The national grid operator. User Any person or organisation using the Distribution System,

but excluding Trans Power. It includes all Customers, embedded generators, and where appropriate, Electricity Retailer's acting on behalf of their customers.

Vegetation Any trees or other plants threatening the WEL Networks overhead lines.

WEL WEL Networks Ltd with its Head Office at the corner of London and Victoria Streets, Hamilton.

WEL Operations The section of WEL responsible for the day to day operations and maintenance of WEL Networks

XLPE Type of insulation – Cross linked Polyethelene Zone Substation Includes HV substations, switching stations, voltage

regulators, ground mounted HV switchgear, large industrial/commercial distribution substations, ripple control plant, and associated protection and controls.


Appendix 2 – Load growth table for zone substations

06/07 07/08 08/09 09/10 10/11 11/12 12/13 13/14 14/15 15/16

Avalon 46.0 23.0 28.0 18.2 18.6 19.1 19.5 20.0 20.4 20.9 21.4 21.9 22.4 Bryce St 46.0 23.0 28.0 22.0 22.6 23.2 23.7 24.3 24.9 25.6 26.2 26.9 27.5 Chartwell 46.0 23.0 28.0 18.6 19.3 20.0 20.6 21.3 22.0 22.6 23.3 23.8 24.3 Claudelands 36.0 18.0 18.0 19.7 20.2 20.7 21.1 21.6 22.2 22.7 23.2 23.8 24.3 Gordonton 10.0 5.0 7.5 5.8 5.9 6.0 6.2 6.3 6.4 6.6 6.7 6.9 7.0 Horotiu 20.0 10.0 15.0 13.5 13.8 14.1 14.4 14.7 14.9 15.2 15.5 15.7 16.0 Kent St 46.0 23.0 23.0 15.7 16.0 16.4 16.8 17.2 17.7 18.1 18.5 19.0 19.4 Latham Court 30.0 15.0 15.0 13.9 14.3 14.6 15.0 15.3 15.7 16.0 16.4 16.7 17.1 Peacockes Rd 20.0 10.0 15.0 13.7 14.0 14.4 14.8 15.1 15.5 15.9 16.3 16.7 17.1 Pukete 11 30.0 15.0 15.0 10.1 10.3 10.6 10.9 11.2 11.5 11.8 12.1 12.4 12.8 Sandwich Rd 46.0 23.0 28.0 20.5 21.0 21.6 22.1 22.6 23.2 23.8 24.3 24.9 25.5 Te Uku 10.0 5.0 7.5 5.1 5.2 5.3 5.4 5.6 5.7 5.8 5.9 6.1 6.2 Wallace Rd 20.0 10.0 15.0 13.2 13.5 13.8 14.2 14.5 14.8 15.1 15.5 15.8 16.2

Western Rd POS 30.0 30.0 19.4 25.2 38.9 39.2 39.5 39.8 40.1 40.4 40.8 41.1 Glasgow St 10.0 10.0 15.0 7.9 8.0 8.2 8.4 8.5 8.7 8.8 9.0 9.2 9.4 Kimihia 10.0 2.5 12.0 3.4 9.0 22.3 22.3 22.3 22.3 22.3 22.3 22.3 22.3 Weavers 15.0 11.3 11.3 7.8 7.9 8.1 8.2 8.4 8.5 8.7 8.8 9.0 9.1

HAMILTON 11 kV POSSUB TOTAL 29.5 30.1 30.7 31.2 31.6 32.1 32.6 33.1 33.6 34.1

BOMBAY POSTe Kauwhata 10.0 5.0 10.0 5.0 5.2 5.3 5.4 5.6 5.7 5.8 6.0 6.1 6.2 Finlayson Rd 5.0 5.0 7.5 3.4 3.4 3.5 3.6 3.7 3.8 3.9 4.0 4.1 4.2 SUB TOTAL 10.0 10.0 15.0 8.4 8.6 8.8 9.0 9.3 9.5 9.7 9.9 10.2 10.4

Forecast Load (MVA)HAM & TWH POS Installed

Capacity

Firm Capacity

N-1

Emer Capacity 4 hours

The above table shows a diagrammatic picture of zone substation capacities, predicted loads and indicative time for remedial action to be taken and is intended as a visual planning tool. Installed capacity, (n-1) firm capacity and short term overload capacity of transformers and where applicable the sub-transmission feeder capacities or 11kV feeder capacities are included. Existing loads are then inserted and load predictions applied over the planning period. From this the zone overload capacity at which remedial action is to be taken can be evaluated. In some zones, sufficient off loading during contingency can be effected and this is taken into account for remedial action planning purposes. Cells in the table are colour coded for clarity and show the normal operating safe region in green, contingency operation in yellow and emergency operation in red. Note that areas of concern highlighted in the above graph will be addressed by the following actions:

• Latham Court and Peacockes Rd will be offloaded by the construction of the new Waikato Zone substation in 2007.

• Horotiu will be offloaded by the construction of new Ngaruawahia zone

substation in 2006.

• Wallace Rd will undergo a zone transformer upgrade, currently planned for 2010.

• Western Road POS offloaded by transferral of the total load to a new Huntly

POS currently planned for 2007/2008.

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